Eni

Annual Report • Apr 5, 2024

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, 2023

OR

• ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to
• ☐ 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

OR

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		* Not for trading, but only in connection with the
Shares)		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 3,375,937,893

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 boxabove 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 financialstatements included in this filing:

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

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

		Page
	Certain defined terms	iii
	Presentation of financial and other information	iii
	Statements regarding competitive position	iii
Glossary		v
	Abbreviations and conversion table	ix
PART 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	20
	History and development of the Company	20
	BUSINESS OVERVIEW	37
	Exploration & Production	37
	Global Gas & LNG Portfolio	67
	Enilive, Refining and Chemicals	71
	Plenitude & Power	80
	Corporate and Other activities	84
	Research and development	84
	Insurance	86
	Environmental matters	86
	Regulation of Eni's businesses	96
	Property, plant and equipment	106
	Organizational structure	106
Item 4A.	UNRESOLVED STAFF COMMENTS	107
Item 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	107
	Operating results	107
	Liquidity and capital resources	122
	Recent developments and significant transactions	127
	Management's expectations of operations	128
Item 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	138
	Directors and Senior Management	138
	Compensation	147
	Board practices	148
	Employees	165
	Share ownership	166
Item 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	167

i

	Major Shareholders	167
	Related parties transactions	167
Item 8.	FINANCIAL INFORMATION	168
	Consolidated Statements and other financial information	168
	Significant changes	168
Item 9.	THE OFFER AND THE LISTING	169
	Offer and listing details	169
	Markets	170
Item 10.	ADDITIONAL INFORMATION	171
	Memorandum and Articles of Association	171
	Material contracts	178
	Exchange controls	178
	Taxation	178
	Documents on display	183
Item 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	184
Item 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	186
Item 12A.	Debt securities	186
Item 12B.	Warrants and rights	186
Item 12C.	Other securities	186
Item 12D.	American Depositary Shares	186
PART II
Item 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	188
Item 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	188
Item 15.	CONTROLS AND PROCEDURES	188
Item 16.	[RESERVED]	189
Item 16A.	Board of Statutory Auditors financial expert	189
Item 16B.	Code of Ethics	189
Item 16C.	Principal accountant fees and services	189
Item 16D.	Exemptions from the Listing Standards for Audit Committees	190
Item 16E.	Purchases of equity securities by the issuer and affiliated purchasers	190
Item 16F.	Change in Registrant's Certifying Accountant	191
Item 16G.	Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual	191
Item 16H.	Mine safety disclosure	194
Item 16I.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	194
Item 16K.	Cybersecurity	194
PART III
Item 17.	FINANCIAL STATEMENTS	198
Item 18.	FINANCIAL STATEMENTS	198
Item 19.	EXHIBITS	199

ii

Certain disclosures contained herein including, without limitation, certain information appearing in "Item 4 – Information on the Company", and in particular "Item 4 – Exploration & Production", "Item 5 – Operating and Financial Review and Prospects" and "Item 11 – Quantitative and Qualitative Disclosures about Market Risk" contain forwardlooking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the "SEC"). In addition, Eni's senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as 'expects', 'anticipates', 'targets', 'goals', 'projects', 'intends', 'plans', 'believes', 'seeks','estimates', variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni's actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled "Risk factors" and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni's expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.

CERTAIN DEFINED TERMS

In this Form 20-F, the terms "Eni", the "Group", or the "Company" refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to "Italy" or the "State" are references to the Republic of Italy, all references to the "Government" are references to the government of the Republic of Italy. For definitions of certain oil and gas terms used herein and certain conversions, see "Glossary" and "Conversion Table".

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolidated Financial Statements of Eni, included in this Annual Report, have been prepared in accordance with International Financial Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

Unless otherwise indicated, any reference herein to "Consolidated Financial Statements" is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.

Unless otherwise specified or the context otherwise requires, references herein to "dollars", "\$", "U.S. dollars", "US\$" and "USD" are to the currency of the United States, and references to "euro", "EUR" and "€" are to the currency of the European 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" (or "GGP"), "Enilive, Refining and Chemicals" (or "Enilive, Refining & C"), "Plenitude & Power" and "Corporate and Other activities".

References to Versalis or Chemical are to Eni's chemical activities which are managed through its fully-owned subsidiary Versalis and Versalis' controlled entities.

References to Plenitude are to Eni's retail gas and power activities and renewables business which are managed through its fully-owned subsidiary Plenitude and Plenitude's controlled entities. The results of the operations of Plenitude are included in the segment information "Plenitude & Power" for financial reporting purposes.

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.

STATEMENTS REGARDING COMPETITIVE POSITION

Statements made in "Item 4 – Information on the Company" referring to Eni's competitive position are based on the Company's belief, and in some cases rely on a range of sources, including investment analysts' reports, independent market studies and Eni's internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.

GLOSSARY

Below is a selection of the most frequently used terms throughout this Annual Report on Form 20-F. Any reference herein to a non-GAAP measure and to its most directly comparable GAAP measure shall be intended as a reference to a non-IFRS measure and the comparable IFRS measure.

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.
Leverage	A non-GAAP measure of the Company's financial condition, calculated as the ratio between net borrowings and shareholders' equity, including non-controlling interest. For a discussion of management's view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, "Ratio of total debt to total shareholders equity (including non-controlling interest)" see "Item 5 – Financial Condition".
Net borrowings	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. 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 (Total Shareholder Return)	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.

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 CO2eq.) 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.

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 GHG Lifecycle Emissions	GHG Scope 1+2+3 emissions associated with the value chain of the energy products sold by Eni, including both those deriving from own productions and those purchased from third parties, accounted on equity basis, net of offset, mainly from Natural Climate Solutions.
Net Carbon Footprint	Overall Scope 1 and Scope 2 GHG emissions associated with Eni's operations, accounted for on an equity basis, net of carbon sinks mainly from Natural Climate Solutions.
Net Carbon Intensity	Ratio between the Net GHG lifecycle emissions and the energy content of products sold accounted for on an equity basis.
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.
Plasmix	Plasmix is the collective name for the different plastics that currently have no use in the market of recycling and can be used as a feedstock in the new circular economy businesses of Eni.

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+	The REDD+ (Reducing Emissions from Deforestation and Forest Degradation) scheme was designed by the United Nations (United Nations Framework Convention on Climate Change - UNFCC). It involves conserving forests to reduce emissions and improve the natural storage capacity of CO2, as well as helping local communities develop through socio-economic projects in line with principles on sustainable management, forest protection and nature conservation.
	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.

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.
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 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 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).

viii

ABBREVIATIONS

mmCF	= million cubic feet
BCF	= billion cubic feet	mmtonnes	= million tonnes MW
mmCM	= million cubic meters BCM	MW	= megawatt GWh
BCM	= billion cubic meters BOE	GWh	= gigawatthour TWh
BOE	= barrel of oil equivalent	TWh	= terawatthour
		/d	= per day
KBOE	= thousand barrel of oil equivalent	/y	= per year
mmBOE	= million barrel of oil equivalent	E&P	= the Exploration & Production segment
BBOE	= billion barrel of oil equivalent	GGP	= the Global Gas & LNG Portfolio segment
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 TABLE

1 acre	= 0.405 hectares
1 barrel	= 42 U.S. gallons
1 BOE	= 1 barrel of crude oil	= 5,232 cubic feet of natural 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)

ix

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

Item 3. KEY INFORMATION

RISK FACTORS

The Group's performance is exposed to the volatility of the prices of crude oil and natural gas and to changing margins of refined products and oil-based chemical products

The price of crude oil and natural gas is the main driver of the Company's operating performance, cash flow, business prospects and its ability to remunerate its shareholders, given the current size of Eni's Exploration & Production segment relative to other Company's business segments in terms of key financial metrics like operating profit, returns and invested capital.

The price of crude oil has a history of volatility because, like other commodities, it is influenced by the ups and downs in the economic cycle and by several macro-variables that are beyond management's control. In the short term, crude oil prices are mainly determined by the balance between global oil supplies and demand, the global levels of commercial inventories and producing countries' spare capacity, as well as by expectations of financial operators who trade crude oil derivatives contracts (futures and options) influencing short-term price movements via their positioning. A downturn in economic activity normally triggers lower global demand for crude oil and possibly 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 outstrip demand, crude oil prices weaken. Factors that can influence the global economic activity in the short-term and demand for crude oil include several, unpredictable events, like trends in the economic growth which shape crude oil demand in big consumer countries like China, India and the United States, financial crisis, monetary variables (the level of inflation and of interest rates), geo-political crisis, local conflicts and wars, social instability, pandemic diseases, the flows of international commerce, trade disputes and governments' fiscal policies, among others.

Long-term demands for crude oil is driven, on the positive side, by demographic growth, improving living standards and GDP (Gross Domestic product) expansion; on the negative side, factors that in the long-term may significantly reduce demands for crude oil include availability of alternative sources of energy (e.g., nuclear and renewables), technological breakthroughs, shifts in consumer preferences, and finally measures and other initiatives adopted or planned by governments to tackle climate change and to curb carbon-dioxide emissions (CO² 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 are likely to materially affect the worldwide energy mix in the long-term and may lead to structural lower crude oil demands and prices. See the section dedicated to the discussion of climate-related risks below.

Notwithstanding the USA being the first oil producer in the world since the shale oil revolution of 2011, global oil supplies are controlled to a large degree by the Organization of the Petroleum Exporting Countries ("OPEC") cartel and its allied countries, like Russia and Kazakhstan, known as the OPEC+ alliance. Saudi Arabia plays a crucial role within the cartel, because it is estimated to hold huge amounts of reserves and a vast majority of worldwide spare production capacity. This explains why geopolitical developments in the Middle East and particularly in the Gulf area, like regional conflicts, acts of war, strikes, attacks, sabotages, and social and political tensions can have a big influence on crude oil prices. Furthermore, due to expectations of a slowdown in the growth rate of the US shale oil production or of a possible decline in the long-term due to capital discipline and industrial factors like a shrinking number of premium locations and high-yield wells, the OPEC+ alliance could exert in perspective an increasingly larger influence over the crude oil market. Finally, sanctions imposed by the United States and the EU against certain producing countries may influence trends in crude oil prices.

To a lesser extent, extreme weather events, such as hurricanes in areas of highly concentrated production like the Gulf of Mexico, and operational issues at key petroleum infrastructures may have an impact on crude oil prices.

In 2023, the price of the Brent benchmark crude declined by 18% compared to 2022 due to rising production levels in non-OPEC countries and expectations among financial market participants of a slowdown in economic activity and hence in demand for crude oil, whereas the China recovery was elusive, and the Europe economies have been stagnating. Prices were supported by curbs to production levels and quotas made by the countries of the OPEC+ alliance. In 2024, the Company expects that crude oil prices will remain at the same level as in 2023 due to continuing production gains and an uncertain macroeconomic backdrop, under the assumption that the OPEC+ alliance still retain its policy of supporting the price of crude oil.

The short-term drivers of prices and demands 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 USA, Qatar and Australia has helped to develop a global liquid market of natural gas, with traders being able to redirect LNG 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 2023 the price of natural gas in USA was one fifth that of Europe, because Europe is a net importer, whilst the USA 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 higher degree of volatility in natural gas prices compared to crude oil. In the long-term, demands for natural gas are exposed to the risks of the transition to a low-carbon economy.

In 2023, natural gas prices declined significantly compared to 2022, with European benchmarks down more than 60%, due to an oversupplied global market and lower consumption driven by lower industrial activity in Europe, energy savings measures, competition from renewables and mild winter weather. We expect weak natural gas prices in 2024 due to continuation of the trends observed in 2024.

The volatility of hydrocarbons prices significantly affects the Group's financial performance. Lower hydrocarbon prices from one year to another negatively affect the Group's consolidated results of operations and cash flow; the opposite occurs in case of a rise in prices. This is because lower prices translate into lower revenues recognised 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. In 2023, lower hydrocarbons prices, down by 18% and 66% respectively for the Brent crude oil and the European spot price of natural gas, reduced our operating profit and cash flow from operating activities by an estimated amount of approximately €5 billion and €3 billion respectively.

Finally, movements in hydrocarbons prices significantly affect the reportable amount of production and proved reserves under our production sharing agreements ("PSAs"), which represented about 55% of our proved reserves as of end of 2023. 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 2023 our reported production and reserves were increased by an estimated amount of respectively 3 KBOE/d and by 30 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 onedollar change in the price of the Brent crude oil.

Eni's Enilive, Refining and Chemical businesses are in cyclical economic sectors. Their results are impacted by trends in the supply and demand of oil products and plastic commodities, which are influenced by the macro-economic scenario and by product margins. 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 shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni's share.

Risks in connection with Russia's military aggression of Ukraine and the Middle East conflict in the Gaza strip

Russia's military aggression of Ukraine began in late February 2022 and has continued to drag throughout 2023 without any prospects of quick solution. This conflict has already negatively impacted the global economy by triggering an energy crisis in Europe, by souring the political relationships between Western countries and Russia, by disrupting supply chains and by increasing cybersecurity threats. In response to Russia's aggression, the EU nations, the UK, and the USA have adopted massive economic and financial sanctions to curb Russia's ability to fund the war, which is negatively affecting the economic activity.

An uncertain global macroeconomic backdrop has been further compounded since last October by a resurgence of tensions in Middle East, culminating in Israelis military invasion of the Gaza strip and risks of enlargement of the conflict.

A prolonged armed conflict in those two areas, a possible escalation of the military action in Middle East, and a further tightening up of the economic sanctions against Russia represent elements of uncertainty that could eventually sap consumers' confidence and deter investment decisions, increasing the risks of a worldwide macroeconomic recession and with it, expectations of a reduction in hydrocarbons demands. This scenario would lead to lower commodity prices and would adversely and significantly affect 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 purchase of natural gas from Russian state-owned company Gazprom and its affiliates, based on long-term supply contracts with take-or-pay clauses. In the past, the volumes supplied from Russia have represented a material amount of our global portfolio of natural gas supplies (see table "Natural gas supply" in Item 4 – Global Gas & LNG Portfolio, providing information about the last three-year period). In 2023, natural gas supplies from Russia decreased materially to 12% of our total purchases of natural gas (down from 28% in 2022) due to unilateral decisions from our Russian supplier to suspend deliveries, against the backdrop of a commercial dispute between the two parties. We intend to continue our effort to substitute Russian-origin natural gas in our portfolio, with the aim to continue to reduce such dependence in the shortest possible timeframe, including the termination of the current contracts.

The Group's business plans have been factoring the assumption of reducing to zero the supplies from Russia and sales plans have been adapted accordingly by limiting sales commitments. To cope with the expected reduced availability of Russian natural gas, the Group has increased purchases from other geographies through various commercial initiatives, such as using contractual flexibilities to increase deliveries from existing long-term contracts or by developing integrated upstream-midstream projects leveraging equity natural gas reserves and new liquefactions capacity. The process of replacing Russian-origin natural gas, including terminating existing contracts, may entail operational and financial risks which may be significant.

Other Eni assets in Russia are immaterial to the Group results of operations (see Item 4).

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

The current competitive environment in which Eni operates is characterized by volatile prices and margins of energy commodities, limited product differentiation and complex relationships with state-owned companies and national agencies of the countries where hydrocarbons reserves are located to obtain mineral rights. As commodity prices are beyond the Company's control, Eni's ability to remain competitive and profitable in this environment requires continuous focus on technological innovation, the achievement of efficiencies in operating costs, effective management of capital resources and the ability to provide 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 segment:

• E&P may be negatively affected by its relatively smaller scale compared to other players in the industry;
• The business of marketing natural gas in the European wholesale market managed by the GGP segment is exposed to pricing competition considering anticipated weak demand trends in Europe and an oversupplied market;
• The businesses of oil refining and production of basic petrochemicals conducted in Europe are exposed to industry cyclicality, weak demand, overcapacity, competition from players with wider scale and cost advantages which are operating in geographies characterized by lower energy costs and environmental exposures compared to Europe, and finally growing market penetration on more sustainable products and solutions; and
• The business of marketing natural gas and electricity to the retail market, which is managed by our subsidiary Plenitude, is exposed to the competitive nature of the retail market that is characterized by an almost full liberalization, a large number of suppliers and customers' ability to switch rapidly from one supplier to another.

More information about the competitive trends of Eni's segments are disclosed in Item 4.

Rising concerns about climate change and effects of the energy transition could continue to lead to a fall in demand and potentially lower prices for hydrocarbons. Climate change could also have a physical impact on our assets and supply chains. 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

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 potential impact and likelihood of the associated exposure for Eni could vary across different time horizons, depending on the specific components of the risk.

We expect that a growing share of our greenhouse gas (GHG) emissions will be subject to regulation, resulting in increased compliance costs and operational restrictions. 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. Our strategy to achieve our target of becoming net zero on all emissions from our operations has resulted in and could continue to require additional costs. We also expect that actions by customers to reduce their emissions will continue to lower demand and potentially affect prices for fossil fuels, as will GHG emissions regulation through taxes, fees and/or other incentives. This could be a factor contributing to additional provisions for our assets and result in lower earnings, cancelled projects and potential impairment of certain assets.

The pace and extent of the energy transition could pose a risk to Eni if we decarbonize our operations and the energy we sell is not aligned to the demand of 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 earnings and financial results. If we move much faster than society, we risk investing in technologies, markets or lowcarbon products that are unsuccessful because there is limited demand for them.

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 their investments in fossil fuel companies. If this were to continue, it could have a material adverse effect on the price of our securities and our ability to access capital markets. Stakeholder groups are also putting pressure on commercial and investment banks to stop financing fossil fuel companies. Some financial institutions have started to limit their exposure to fossil fuel projects. Accordingly, our ability to use financing for these types of future projects may be adversely affected. This could also adversely affect our potential partners' ability to finance their portion of costs, either through equity or debt.

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. We expect to see additional regulatory requirements to provide disclosures related to climate risks.

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. The Company's traditional oil and gas business may increase or decrease depending upon regulatory or market forces, among other factorsIf 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. 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 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.

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 lowercarbon alternatives. Current and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring or sequestering emissions.

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 increase in the amount of energy generated by renewables, the possible emergence of new products and technologies, as well as changing consumers' preferences.

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 fail 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 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 who have allegedly made the most significant contributions to climate change to account. Courts may condemn oil and gas companies to compensate individuals, communities, and states for the economic losses due to global warming as a consequence 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.

For example, we are defending in California against claims brought to us by local administrations and certain associations of individuals who are seeking compensation for alleged economic losses and environmental damage due to climate change.

Private individuals, associations and NGOs may also bring legal actions against states or companies to get them condemned to adopt stricter targets in 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 alleging that Eni and agencies of the Italian State are liable for climate change. The plaintiffs claimed economic losses and other damages and requested that Eni revises its decarbonisation strategy and immediately stops any harmful conducts, alleging several environmental crimes and violations of human rights.

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.

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.

The reputational risk of oil&gas companies owes to the growing perception by governments, financial institutions, and the general public that those companies may be 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.

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.

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 and business prospects.

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 shareholder returns, including dividends and the price of Eni's shares.

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

We are building our portfolio of low-carbon products and services such as electricity generated from solar and wind power, biofuels, projects for permanent geological sequestration of CO² , and charging for electric vehicles through organic and inorganic growth.

In expanding our offerings of these low-carbon products and services, we expect to undertake acquisitions and form partnerships. The success of these transactions will depend on our ability to realise 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 realise the expected returns from these transactions.

The operating margins for our low-carbon products and services may not be as high as the margins we have experienced historically in our oil and gas operations.

Therefore, developing our low-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.

Risks 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 Enilive and 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, which are possible consequences of climate change.

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 require high levels of capital expenditures and are 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, significant impact on Eni's future growth prospects, results of operations, cash flows, liquidity, and shareholders' returns.

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 2023, approximately 70% of Eni's total oil and gas production for the year derived from offshore fields, mainly in Egypt, Norway Libya, Angola, Kazakhstan, Indonesia, Venezuela, the United Arab Emirates, Congo and the United States. 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 heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents. A large part of the Company 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 possible 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. Those activities include appraising a discovery, defining contractual and fiscal terms and conditions with state-owned entities and other partners to reach a final investment decision, and building and commissioning large-scale plants and equipment. Delays in the construction of key plants and facilities or in obtaining all necessary authorizations from competent authorities, costs overruns due to unplanned drilling and other operational conditions, as well as unexpected events resulting in temporarily stoppage of activities (e.g. third-party claims, environmentalists protests, changes to the work scope requested by governmental authorities, contractors' underperformance) could significantly and adversely affect projects' expected returns. Moreover, projects executed with partners and joint venture partners reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations and performance of its partners. The occurrence of any of such risks may negatively affect the time-to-market of the reserves and may cause cost overruns and start-up delays, lengthening the project pay-back 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.

The Group is currently engaged in the execution of several development projects to put into production its proved oil and natural gas reserves. The Company has changed its approach on how to manage development projects in the hydrocarbon segment, which normally feature long-lead times. In recent years we have implemented a phased approach to developing activities so to accelerate the production start-up, as well we have favoured near field development to exploit synergies with existing infrastructures and reutilization/reconversion of existing plants and vessels. This strategy in developing activities is intended to shorten the time-to-market of reserves and to accelerate the pay-back period. However, the achievement of the expected time-to-market and execution of development projects on time and on budget depends on several elusive factors which are inherently difficult to schedule:

• appraising a discovery to evaluate the technical and economic feasibility 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 floating production storage and offloading (FPSO) vessels, floating units for the production of liquefied natural gas (FLNG) and platforms, as well as building transport infrastructures to export production to final markets;

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

• carefully planning the commissioning and hook-up phase where mismanagement might lead to delays to achieve first oil;

• changes in operating conditions and cost overruns. We expect the prices of key input factors such as labour, basic materials (steel, cement, and other metals) and utilities to remain elevated in the next year or two until inflationary pressures throughout the entire supply chain moderate on the back of a slowing economy. We also expect daily rates of leased rigs and other drilling vessels and facilities to not come down as much as oil companies competes for a stable amount of supply of this kind of equipment considering the restructuring the oilfield service sector has undergone due to reduced capital spending by their clients.

All the above-mentioned factors can cause delays and cost overruns therefore negatively impacting expected rate of returns of projects, also considering the volatility of hydrocarbons prices.

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

Future oil and gas production is a function of 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 judgment 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-ofthe-month commodity prices for the preceding 12 months. For the 12-months ending at December 31, 2023, average prices were based on 83 \$/barrel for the Brent crude oil, lower than the 2022 reference price 101 \$/barrel, resulting in us having 37 million BOE of reserves that have become uneconomical at a lower price and were therefore removed from proved reserves.

Accordingly, the estimated reserves reported as of the end of 2023 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, 2023, approximately 38% 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 it can and will make these expenditures and conduct these operations successfully. These assumptions may prove to be inaccurate and are subject to the risk of a structural decline in the prices of hydrocarbons, which could reduce available funds to develop PUD and/or make development uneconomical. The Group's reserve report as of December 31, 2023 includes estimates of total future development and decommissioning costs associated with the Group's proved total reserves of approximately €42.6 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities; €44.3 billion in 2022). It cannot be certain 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 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 as a result of, among other things, changes in commodity prices, changes in cost of oil services, 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 or its credit facilities or issuance of new bonds is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of Eni's reserves, which in turn could adversely affect its results of operations and cash flows and its ability to achieve its growth plans. In the four-year plan we are forecasting significant capital expenditures in a range of €5.5-6 billion on average per year to fund new exploration and development projects and production ramp ups and considering expected continuation of inflationary trends in upstream costs. In case of a decline in hydrocarbons prices, 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 a 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.

In 2022, in response to a surge in hydrocarbons and electricity prices also due to the disruption risks in connection with the Russian military aggression of Ukraine, governments of EU member states and of UK enacted solidaristic contributions in the form of one-off or temporary windfall levies to increase the fiscal take on the profits of energy companies relating to the portion of those profits deemed to exceed historical averages, to collect funds to alleviate the financial burden on households and businesses due to rising costs of fuels and energy. These windfall taxes negatively affected our results of operations and cash flow in 2022 and, to a lesser extent, in 2023.

Notwithstanding hydrocarbons and electricity prices have significantly declined in 2023 compared to 2022, they are still perceived to remain at historically high values by governments and consumers. Given rising pressures on public finances due to an expected economic slowdown and the general consideration that the oil&gas companies may be 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, which could negatively affect the Group's results of operations and cash flows.

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

In the Supplementary oil & gas information, it is indicated the present value of future net revenues from Eni's proved reserves that may differ from the current market value of Eni's estimated crude oil and natural gas reserves. In accordance with the 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.

The Group may fail to execute in whole or in part its asset disposition plan and/or realise the returns and proceeds expected from it.

Our financial plan for the next four-year period 2024-2027 contemplates a gross capital expenditures program of around €35 billion and asset dispositions of about €8 billion (net of expected disbursements for acquisitions) leading to a net cash flow for investing activities of about €7 billion per year on average. The ability of the Group to successfully realize such asset dispositions is exposed to several risks, such as the Group's failure to find purchasers of the assets and effect the dispositions at the price or on the terms that were anticipated. These risks are particularly significant in the current environment dominated by high interest rates, where, therefore, financing for perspective buyers could be limited, and volatility, where asset valuations can fluctuate significantly and unpredictably. The Group's failure to realise in whole or in part its disposition plan and/or realise the expected returns and proceeds may adversely affect the Group's cash flows and, therefore, the Group's ability to fund its capital expenditure programs and/or distribution policy.

Further, dispositions have their own risks associated with the separation of operations and personnel, the potential provision of transitional services and the allocation of management resources. Dispositions may also involve continued financial involvement of the Group in the divested business, such as through guarantees, indemnities or other financial obligations and may result in lost synergies that could negatively impact our balance sheet, income statement and cash flows.

Risks related to political considerations

As at 31 December 2023, about 82% of Eni's proved hydrocarbon reserves were located in non-OECD (Organisation 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 United States 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; exports;
• difficulties in finding qualified international or local suppliers in critical operating environments; and
• complex processes of granting authorizations or licenses affecting time-to-market of certain development projects.

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

Eni's operations in Libya are exposed to significant 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, 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 that timeframe, albeit of a smaller scale compared to 2011. In 2023, notwithstanding a stalemate in the process of reunification of the Country, the coexistence of the Government of National Unity installed in Tripoli and the self-appointed National Stability Government installed in the east of the country has paved the way to a relatively higher degree of stability. In 2023, Eni production in Libya was 162 KBOE/d, equal to 11% of the Group's total production, and was in line with management's plans. Management believes that Libya's geopolitical situation will continue to represent a source of risk and uncertainty to Eni's operations in the country and to the Group's results of operations and cash flow.

The financial difficulties of Venezuela partly due to the US sanction regime have impaired our ability to conduct profitable operations in the country. Currently, after having completely impaired other projects in past reporting periods, the Company retains just one 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 failed to regularly pay the receivables for the gas volumes supplied by Cardón IV venture and consequently a significant amount of overdue receivables is outstanding at the closing date of the financial year 2023 and a credit loss provision has been booked to reflect the counterparty risk. As of 31 December 2023, Eni's invested capital in Venezuela was approximately €1 billion, mainly relating to trade receivable owed to us by PDVSA. Due to a partial lifting of US sanctions on the trade of Venezuelan crude oil, Eni was able in 2023 to obtain the reimbursement in-kind of a portion of its trade receivables, so to partly offset the increase of the year due to the current natural gas production and revenues. However, there is still a great deal of uncertainty about any possible evolution of the US sanctions against Venezuela and our ability to recover our outstanding receivables.

The Group has significant credit exposure towards state-owned and privately-held local companies in Nigeria in relation to their share of funding of petroleum projects operated by Eni. A significant amount of receivables owed to us was past due as at December 31, 2023 because of Eni's Nigerian counterparts inability to reimburse their share of expenditures funded by us reflecting a deteriorated financial framework of the Country.

Furthermore, Eni's operations in Nigeria were negatively affected by continuing acts of theft of oil at onshore pipelines in past years and, to a lesser extent, also in 2023.

Egypt has been experiencing financial restraints due to an economic slowdown and a contraction in reserves of foreign currencies. Eni is currently supplying its equity share of natural gas production to local state-owned oil companies that have failed to pay trade receivables owed to us in a timely manner. On the basis of the commitments of the country's authorities to normalize the outstanding exposure towards Eni, an expected credit loss was estimated taking into account the expected timing of collection.

Sanction targets

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

As 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. Considering the complexity of the sanctions and the existing Eni's contracts for natural gas supply from Russia and the need to make payments to Russian counterparties, the Company is exposed to the risk of possible violations of the sanction's regime.

Eni 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.

From 2017, the United States have enacted a regime of economic and financial sanctions against Venezuela. The scope of the restrictions, initially targeting certain financial instruments issued or sold by the Government of Venezuela, was gradually expanded over 2017 and 2018 and then significantly broadened during the course of 2019 when PDVSA, the main national state-owned enterprise, was added to the "Specially Designated Nationals and Blocked Persons List" and the Venezuelan government and its controlled entities became subject to assets freeze in the United States. Even if such U.S. sanctions are substantially "primary" and therefore dedicated in principle to U.S. persons only, retaliatory measures and other adverse consequences may also interest foreign entities which operate with Venezuelan listed entities and/or in the oil sector of the country. The U.S. sanction regime against Venezuela was further tightened in 2020 by restricting any Venezuelan oil exports, including swap schemes utilized by foreign entities to recover trade and financing receivables from PDVSA and other Venezuelan counterparties. This latter tightening of the sanction regime has reduced the Group's ability to collect the trade receivable owed to Eni for its activity in the country in 2021 and 2022, except for limited waivers agreed with US relevant authorities. which have recently relaxed the sanction regime. In the final part of 2023, the US sanction regime against Venezuela was relaxed and that has enabled Eni to lift some PDVSA's entitlements of crude oil and to compensate overdue amounts of trade receivables owed to us in connection with our supplies of equity natural gas to PDVSA.

Eni carefully evaluates on a case-by-case basis the adoption of adequate measures to minimize its exposure to any sanctions risk which may affect its business operation. In any case, the U.S. sanctions add stress to the already complex financial, political, and operating outlook of the country, which could further limit the ability of Eni to recover its investments in Venezuela.

Specific risks of the Company's gas business in Italy

a) Current, negative trends in the competitive environment of the European natural 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 few 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 (Russia, Algeria, Libya 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 due to the current competitive dynamics in the European gas markets. In past downturns of the gas sector, the Company incurred significant cash outflows in response to its take-or-pay obligations. 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

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 retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users who opt to adhere to regulated tariffs until the market is fully opened. 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 cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results, and cash flow. In the current environment characterized by rising energy costs, it is possible that the Authority may enact measures intended to limit revenues of inframarginal power generation and to reduce the indexation of the cost of the raw materials in pricing formulae applied by retail companies that market natural gas and electricity to residential customers and that development could negatively affect our results of operations and cash flow in the domestic retail business of natural gas and power. In the current energy context, characterized by many regulatory interventions at EU and national level aimed at ensuring security of supply and curbing consumptions and energy prices for final customers, also our GGP business that engages in the wholesale marketing of natural 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 natural gas and electricity.

Risks related to environmental, health and safety regulations and legal 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 natural 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 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.

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

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 nature because of flammability, dangerousness, and toxicity of hydrocarbons and of objective risks of industrial processes to explore, develop, extract, refine, handling and transport oil, natural gas, liquified 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 plug-in 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 tons 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. 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 and to safeguard the environment and the health and safety of employees, contractors and communities involved by the Company operations, including:

• costs to prevent, control, eliminate or reduce certain types of air, soil and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change (see the specific section below on climate-related risks);
• 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;
• 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 groundwater, soil or the atmosphere, or violations of HSE laws.

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 susceptible to risks of blowout, fire and loss of containment and, given that normally high volumes are involved, could present significant risks to people, the environment and the 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 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 drivers could cause any if the incidents described herein of various magnitude which could lead 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.

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 environmental impact of its past and present industrial activities which has given rise to litigation with administrative bodies and third parties. 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 as a result 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. 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, 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 Italian sites, 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. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective 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 a number of 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 involve the alleged breach of anti-bribery and anti-corruption laws and regulations and other ethical misconduct. Such proceedings are described in the "Item 18 - Notes to the consolidated financial statements", under the heading "Legal Proceedings". 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 that act on the Group's behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni's reputation and shareholder value.

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. At the beginning of 2024, Eni completed the acquisition of the group Neptune Energy with a transaction value of €2 billion, which represent the largest acquisition made by Eni in recent years and this deal could entail integration risks.

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 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.

e) 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 (viruses, computer intrusions), user errors or natural disasters. The 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. 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, the Group cannot guarantee that its security measures will be sufficient to prevent a material disruption, breach or compromise in the future. 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. If any of the risks set out above materialise, 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 share.

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 the vast majority of 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 of 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 materialise, 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 and products 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 longterm 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 trading to optimize commercial margins or with a view of profiting from expected movements in market prices. 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 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.

Eni's credit ratings are potentially 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 the Company could be downgraded.

Eni is exposed to credit risk. Eni's counterparties could default, could be unable to pay the amounts owed to it 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 of the Company and cashflow shortfall.

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 materializes, this 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.

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 name of the agent of Eni in the United States is Marco Margheri, Washington DC – USA 601, 13th street, NW 20005.

The Company 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 reduce in the long term its dependence on hydrocarbons and to increase the weight of decarbonized products in its portfolio with the aim of reaching the target of net-zero greenhouse gas emissions by 2050 to pursue the most ambitious target of the Paris Agreement to limit global average temperature increase to 1.5°C by the end of the century. Management believes this strategic shift away from traditional hydrocarbons will place the Company in a very competitive position in the market for the supply of de-carbonized products, combining value creation, business sustainability and economic and financial robustness, lessening the Company's dependence on the volatility of the results of the hydrocarbons businesses. To execute this strategy, the Company has established two business Groups.

The Natural Resources Business Group is committed to build up in a sustainable way, the value of Eni's Oil & Gas upstream portfolio, with the objective of reducing its carbon footprint by scaling up energy efficiency and expanding production in the natural gas business, and its position in the wholesale market. Furthermore, it is focused on the development of projects to capture and store CO² emissions and of carbon sink, mainly through initiatives of Natural Climate Solutions like the projects for forests conservation and rehabilitation, carried out mostly in developing Countries, that qualify as REDD+ projects.

The Energy Evolution Business Group is engaged in the evolution of the businesses of power generation, transformation and marketing of products from fossil to bio, blue and green. In particular, it is focused on growing power generation from renewable energy and biomethane, it coordinates the bio and circular evolution of the Company's refining system and chemical business, and it further develops Eni's retail portfolio, providing increasingly more decarbonized products for mobility, household consumption and small enterprises. The Business Group includes results of the Enilive and Refining business, the chemical business managed by Versalis SpA and its subsidiaries, the Eni Plenitude SpA Società Benefit ("Plenitude") and its subsidiaries which combines renewables generation, gas and power retail and business customers, electric vehicle charging and energy services in a unique and integrated business model. In addition to these activities, this business Group include the results of power generation from thermoelectric plants and the activities of environmental reclamation and requalification implemented by the subsidiary company Eni Rewind.

For IFRS segmental reporting purposes, Eni's principal segments of operations are described below:

• Exploration & Production: engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 35 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 2023, Eni's average daily production amounted to 1,529 KBOE/d on an available- for-sale basis. As of December 31, 2023, Eni's total proved reserves amounted to 6.4 BBOE, which include subsidiary undertakings and proportionally consolidated entities and Eni's share of reserves of equity-accounted joint ventures and associates.
• 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 optimizing the gas asset portfolio. In 2023, Eni's worldwide sales of natural gas amounted to 50.51 BCM, of which 24.40 BCM was in Italy. The LNG business includes the purchase and marketing of LNG worldwide, with a large proportion of equity LNG supplies.

● Enilive, Refining and Chemicals: engages in the supply of biofeedstock and crude oil supply, in the storage, production, distribution and marketing of biofuels, oil products, biomethane, smart mobility solutions and mobility services, and in the distribution of basic chemical products, intermediates, elastomers and chemicals from renewable sources. The results of operations of the Enilive and Refining business and of the chemical business have been combined in a single reporting segment because the businesses exhibit similar characteristics. Oil and products trading activities are designed to perform supply balancing transactions in the market and to stabilize or hedge commercial margins. As of December 31, 2023, the balanced traditional and bio-feedstocks based refining capacity was 528 KBBL/d and 1.65 million tonnes/year, respectively. In 2023, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to 19.75 mmtonnes (of which traditional refinery throughputs were 18.88 mmtonnes and bio refinery throughputs were 0.87 mmtonnes) and sales of refined products were 28.01 mmtonnes, of which 22 mmtonnes were in Italy. Retail sales of refined products at Eni's service stations amounted to 7.51 mmtonnes in Italy and in the rest of Europe. In 2023, Eni's retail market share in Italy through its "Eni" branded network of service stations was 21.4%.

In the Chemical business Eni, through its wholly-owned subsidiary Versalis, 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. Activities are concentrated in Italy, in Europe and in the rest of the world. In 2023, production volumes of chemicals amounted to 5,663 ktonnes.

● Plenitude & Power: engages in the activities of retail marketing of gas, power and related services, in the production and wholesale marketing of power produced by both thermoelectric plants and from renewable sources, as well as in the e-mobility services. It also comprises trading activities of CO2 emission allowances to help stabilize/hedge the Clean Spark Spread (CSS) of gas-fired power production and the power sales commercial margin. As of December 31, 2023, Eni's customer base was over 10 million retail points of delivery (gas and electricity) in Europe (of which 8.2 million were in Italy). In 2023, retail power sales to end customers, managed by Plenitude and subsidiary companies in France, Greece and Iberian Peninsula, amounted to 17.98 TWh. Retail gas sales, in Italy and in European markets, amounted to 6.06 BCM.

Eni is engaged in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore) through Plenitude which engages in building, commissioning and managing renewable energy producing plants. As of December 31, 2023, the installed capacity from renewable sources was 3.0 GW, up by 0.8 GW compared to 31 December 2022 (2.2 GW).

When considering installed capacity at other Eni's business segments, Eni Group installed capacity from renewables amounted to 3.1 GW as of December 31, 2023 (2.3 GW as of December 31, 2022)

With reference to the e-mobility business, as of December 31, 2023, Eni's network of charging stations for electric vehicles included approximately 19,000 installed charging points distributed throughout the European territory, in particular in Italy.

As of December 31, 2023, the installed operational capacity of Eni's thermoelectric plants was 2.2 GW, with a total power generation of 20.66 TWh in 2023.

● 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 the economics of the forestry projects (REDD+), projects for CO2 capture and storage and/or utilization and agribusiness.

Eni's registered head office is located at Piazzale Enrico Mattei 1, Rome,Italy (telephone number: +39-0659821).

Eni branches are located in:

San Donato Milanese (Milan), Via Emilia, 1; and

San Donato Milanese (Milan), Piazza Ezio Vanoni, 1. Internet address: eni.com

A list of Eni's subsidiaries is provided in "Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements".

Strategy

The Company is executing a strategy designed to embrace the energy transition and drive a significant improvement in our businesses' financial and industrial performance. Through this strategy, we intend to advance the Company's transformation and to grow in a low-carbon economy, delivering on Eni's stated long-term goal of achieving the carbon neutrality of our industrial processes and products by 2050, addressing GHG emissions of scope 1, 2, and 3. We plan to monetize the value of our legacy businesses and skills while accelerating the development of new businesses related to the energy transition, where we expect high growth and consistent returns. The strategic guidelines that will drive our plans going forward are:

• 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 maximize the integration of the portfolio along the entire energy value chain;
• To retain capital discipline built upon selecting investment opportunities following strict return criteria and executing a divestment plan to balance growth expenditures better and to maintain strong financial metrics and flexibility;
• To ensure competitive and progressive returns to shareholders;
• To grow the natural gas component of our business, also expanding trading opportunities by strengthening integration between the E&P and GGP segments, as well as to develop the businesses of renewable energies, biofuels, marketing of energy and fuels to retail customers, biochemistry, the circular economy, and carbon removal solutions;
• To leverage our proprietary technologies to underpin the development of new businesses;
• To develop our distinctive satellite business model by leveraging our asset portfolio in two ways. First, we have established controlled entities focused on specific, high-growth market segments related to the energy transition, which can attract dedicated third-party capital, thus enabling Eni to unlock the value of such businesses. As part of this, in March 2024, we finalized an agreement with an institutional investor who has subscribed to a dedicated share capital increase of our Plenitude subsidiary, engaged in renewables, energy retail, and EV recharging, acquiring a 7.6% minority interest with about €0.6 billion cash proceeds credited to Eni. Secondly, we have created financially independent jointly controlled entities or associates in our legacy businesses by contributing our assets to newly established ventures with other operators in specific geographies, aiming to maximize operational and financial synergies, enhance growth opportunities, and harvest dividends. As part of this latter approach, in recent years, we established Azule Energy in Angola and Vår Energi in Norway by spinning-out our oil&gas assets in such geographies to financially independent entities, which have been paying significant dividends to Eni (e.g., in 2023, we collected €1.47 billion of dividends from those entities);
• To leverage alliances and collaboration with a wide range of stakeholders by developing mutually beneficial solutions and synergies. As part of this guideline, we have successfully grown our vertically integrated agricultural business in several African countries to produce a renewable feedstock for manufacturing biofuels with a low carbon footprint at our biorefineries in Italy. This project applies the best sustainability and circular economy standards by repurposing abandoned land and favorably contributing to local job creation and development without competing with the food chain.

Our financial plans for the next four-year period 2024-2027 assume a flat Brent crude oil price of 80 \$/bbl, a gross capital expenditures program of around €35 billion, and the execution of asset disposals of about €8 billion (net of expected disbursements for acquisitions) leading to a net cash flow for investing activities of about €7 billion per year on average. Our future performance is expected to be driven by: profitable production growth in E&P, expansion of the renewable generation capacity, continuing margin optimizations at our GGP business leveraging integration with upstream equity projects, steady profitability in the refining business helped by product optimization and cost efficiencies, the upgrading of the manufacturing capacity of biofuels and the ramp up of vertical integration with the agricultural business in Africa to secure cheap and reliable feedstock for our biorefineries, strong marketing performance in retail sales of increasingly decarbonized fuels and energy products and the restructuring of our petrochemical business managed by Versalis by growing sales of biochemicals and highperformance polymers.

Our expectations for improving profitability and cash generation at a constant scenario basis in the next four-year plan, driven by the execution of our strategy, coupled with our current strong balance sheet and financial flexibility, will enable us to enhance shareholders' remuneration going forward (see Item 5 – remuneration policy).

We plan to maintain a strong balance sheet and leverage ratio, which is projected to remain close to our stated mediumterm range of 0.15-0.25 at the beginning of the plan and then declining towards the low end of the range at the end of the plan, by means of a disciplined approach to capital selection, a cost saving program of €1.8 billion, the execution of a disposal program of €8 billion (net of expected cash-outs for acquisitions) and continuing cash flow improvement actions (see Item 5 in the looking forward section).

Decarbonization strategy

The Company's medium- and long-term strategy and action plan are expected to drive a significant improvement in our carbon footprint, in line with our objective of the carbon neutrality of all our industrial activities, processes, and products sold to customers by 2050. The pathway that is designed to lead Eni to carbon neutrality by 2050 consists of a series of targets that include first net zero emissions (Scope 1+2) of the Upstream business by 2030 and Eni Group by 2035 and then achieving net zero emissions by 2050 of all Scope 1, 2 and 3 GHG emissions associated with the life cycle of products sold.

The implementation of our strategy and our action plan over the coming years are expected to drive a gradual reduction in our Scope 1+2+3 GHG emissions until we achieve carbon neutrality in 2050 per the following intermediate steps and goals:

• Net Zero Carbon Footprint Upstream (Scope 1+2) by 2030, with intermediate targets of -50% by 2024 and -65% by 2025 vs. 2018, and Net Zero Carbon Footprint Eni by 2035;
• -35% of Net GHG Lifecycle Emissions (Scope 1+2+3) by 2030 vs. 2018, -55% by 2035 and -80% by 2040;
• -15% of Net Carbon Intensity of energy products sold by2030 vs. 2018 and -50% by 2040.

We plan to utilize carbon offsets to compensate for the remaining emissions, mainly from natural climate solutions, contributing about 5% of the total supply chain emissions reduction by 2050. This pathway consists of a multitude of decarbonization levers, which function according to market dynamics. It is designed to be in line with society's evolution and the so-called energy trilemma, namely the need to combine the three key objectives of environmental sustainability, security of supply, and energy affordability.

Significant effort has been made in recent years, enabling the achievement of important milestones that form the basis of our future goals:

• Rebalancing the upstream portfolio favoring the gas component, thanks partly to recent business combinations (e.g., Neptune Energy, bp Algeria). These transactions reflect a commitment to target a 60% gas production level (including condensates) by 2030 and above 90% after 2040;
• Continuing biorefining development, with the startup of the Chalmette plant in the United States, agreements to convert the Livorno refinery in Italy, and agreements for the potential development of plants in South Korea and Malaysia. These actions are instrumental in achieving an "organic" refining capacity of more than 5 million tons by 2030 (with an intermediate target of more than 3 million tons by 2023);
• Increasing Plenitude's installed renewable capacity, with the goal of installing more than 15 GW by 2030 (with intermediate targets of 4 GW by 2024 and more than 8 GW by 2027), rising to 60 GW by 2050 (in the context of growing the customer base to more than 20 million by 2050);
• Establishing Plenitude as one of the most significant players in the electric vehicle charging service in Italy and Europe, through Be Charge and with its approximately 19,000 electric vehicle charging points installed in 2023. Business development for sustainable mobility includes installing about 40,000 electric vehicle charging points by 2027 and about 160,000 by 2050;
• Increasing new energy carriers production (e.g., power with CCS) and magnetic fusion, with the first operational plant expected in the early 2030s;
• Acquiring leadership positions in the UK and Italy to develop dedicated CO2 storage hubs for hard-to-abate emissions.

A gradual growth in the share of investments dedicated to new energy products and services will support the evolution toward a decarbonized product portfolio. The share of spending dedicated to Oil & Gas activities is expected to be gradually reduced, and major investment projects will be evaluated in line with emission reduction targets and the commitment to phase out investments in highly emissive "unabated" activities or products as a necessary condition to achieve carbon neutrality by mid-century. Expenditure earmarked for zero and low-carbon activities will amount to €12.8 billion over the 2024-27 four-year plan.

TCFD disclosures on carbon neutrality by 2050

Aware of the need to achieve carbon neutrality by 2050 in line with international climate objectives, Eni has embarked on an industrial transformation that will enable it to achieve net zero by 2050. To ensure transparency to its stakeholders, Eni is 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 Corporate Sustainability Reporting Directive (CSRD) and the European Sustainability Reporting Standards (ESRS)). This exercise may lead to integrating new tools for corporate climate disclosure.

Climate change-related risk management

The process of identifying and assessing climate-related risks is part of the Eni Integrated Risk Management Model, developed to ensure that decisions consider risks from an integrated, comprehensive, and forward-looking perspective. The process guarantees the detection, consolidation, and analysis of Eni risks and supports the BoD in verifying the compatibility of the risk profile with the strategic objectives from a medium to long term perspective by monitoring the evolution of the key risks and de-risking actions. Risks, including climate change, are assessed considering both the probability of occurrence and the quantitative and qualitative impacts on Eni's objectives determined in a given time horizon if the risk were to occur. Risks are also represented on matrices that allow them to be compared and classified by relevance.

Risks related to climate change are analyzed, assessed, and managed considering the TCFD's recommendations. These recommendations refer to both risks associated with energy transition (regulatory, legal, market scenario, technological evolution, and reputational aspects) and physical risk (acute and chronic) through an integrated and transversal approach involving the relevant functions as well as the business lines. Risks related to executing planned strategic actions to mitigate climate change are also considered.

The energy transition policies implemented by the governments of numerous states significantly influence the context in which Eni operates. These policies define the course of action to realize the commitments made by countries under the Paris Agreement, particularly with the agreement reached at COP28 on Global Stocktake, which makes explicit reference for the first time to the need to "transition away from fossil fuels." Commitments to achieving carbon neutrality and the possible change of consumer preferences could lead to a structural decrease in demand for hydrocarbon in the medium to long term and an increase in the operating costs of the oil & gas sector.

Uncertainties about demand trends and the economic feasibility of decarbonization technologies make long-term investment decisions increasingly risky. In addition, the increasing polarization of the public debate on climate change and the rigorous scrutiny by various stakeholders could lead to difficulties in accessing capital and challenge the "license to operate" of the companies. In response to these emerging trends, Eni is committed to the execution of a portfolio repositioning strategy based on gradually reducing the weight of hydrocarbons to benefit the growth of renewable energy, biofuels, sustainable and environmentally friendly chemicals, as well as the development of emission capture/abatement technologies and low-carbon energy carriers.

a) Regulatory risk: increasing worldwide efforts to tackle climate change may lead to adopting stricter regulations to curb carbon emissions, which could increase expenditures in the short term and may end up suppressing demand for our products in the medium to long term.

At the global level, given countries' commitment to decarbonization, it is conceivable that regulatory developments will lead to the diffusion of new carbon pricing mechanisms and obligations to introduce minimum market shares of renewable/lowcarbon fuels in the medium to long term. Regarding the European context, Eni is subject to the European Emission Trading Scheme (EU ETS) and the UK Emission Trading Scheme (UK ETS) for about half of its direct GHG emissions. Under this mechanism, the company must purchase emission allowances to cover the excess over its free allocations. Regarding the non-EU area, several developing economies have announced the implementation of carbon pricing mechanisms. However, these CO2 prices are expected, at least at an initial stage, to be low and have an insignificant impact on Eni's activities. In addition, the possible adoption of measures aimed at decreasing hydrocarbon consumption or introducing mining restrictions could reduce the growth prospects of the traditional business, resulting in the need to accelerate portfolio diversification.

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

Currently, the market is characterized by high uncertainty due to the simultaneous action of several variables: geopolitical tensions, decarbonization policies (extremely uneven geographically), and supply and demand trends. This scenario accentuates the complexity of investment decisions and decreases the predictability of how and when the energy transition will take place. Additionally, technological innovation plays a crucial role in the transition plans of Oil & Gas companies. In the medium to long term, several technologies aimed at building a low-carbon energy consumption model could reach the commercial stage, for example, in electric mobility, energy storage from renewable sources, and the development of new energy carriers. Eni is developing new technologies and energy carriers to transform its portfolio, such as emission capture and storage, hydrogen production/transport, and magnetic confinement fusion. Failure to anticipate shifts in the supply/demand trends and fundamental technologies in the energy transition could significantly affect growth prospects, operating results, cash flow, and shareholder returns.

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; such legal actions may be brought against us.

Several public and private entities have initiated legal proceedings against major Oil & Gas companies based on presumptions of liability for climate change-related impacts, alleged human rights violations, and so-called "greenwashing" practices. Some institutional investors or members of civil society have obtained judgments condemning oil companies to adopt faster decarbonization plans (although various levels of judgment have yet to be heard); in other cases, they have demanded recognition of the Board's responsibility for managing climate strategy or have promoted shareholder resolutions interfering with corporate plans. In 2023, Eni was sued by NGOs and private citizens for alleged responsibility for climate change. Eni is also a party to some proceedings in California brought by various business entities that complain of revenue losses due to climate change and claim compensation from oil companies. These events demonstrate how some institutions and stakeholders are questioning the license to operate of western oil companies perceived by them as unvirtuous or reluctant to adapt their business model and capital allocation processes to the decarbonization scenario, creating new risk profiles for operators in the legal field.

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 matters of shareholders' resolutions.

In the increasing polarization of the public debate on climate change, part of civil society (environmental movements, NGOs, younger generations), government institutions, and other stakeholders perceive Oil & Gas companies as primarily responsible. This debate increases pressure on oil company boards to accelerate transition strategies and plans and on the financial sector (asset managers, banks, and insurance companies) to align their portfolios with "Net Zero" targets. Recently, some large banks and financial institutions, especially in Europe, have announced to stop direct financing of new Oil & Gas projects. The financial world's disengagement from hydrocarbons could lead to difficulties accessing the capital market and increasing pressure on Oil & Gas companies' stocks, resulting in higher financing costs and equity risk.

e) Physical risk: extreme weather phenomena, allegedly caused by climate change, may disrupt our operations.

Based on studies in the scientific community, the increased frequency of acute and chronic weather and climate phenomena with high impact on the economy and life of communities, such as, but not limited to, hurricanes, floods, droughts, desertification, rising ocean levels, melting of perennial glaciers, and others, is related to climate change. Extreme weather events could cause prolonged disruptions of industrial operations and damage to facilities and infrastructure, leading to loss of results and cash flow and increased costs of repair and maintenance, including effects on the supply chain.

Eni has adopted a structured risk management process for identifying and analyzing assets exposed to potential changes in natural events (acute and chronic) in the medium to long term, which may impact the operability and safety conditions of the assets themselves. This process allows us to consider different climate scenarios, consistent with varying emission scenarios and time horizons of short (5/10 years), medium (10/20 years), and long term (20/30 years). Based on data provided by specialized data providers, the inherent risk of the assets (understood as the inherent exposure an asset has to a specific natural event due solely to its location and the evolution of the climate scenario) and the residual risk (understood as the risk level assessed after considering mitigations already in place or planned) are assessed. After mitigation actions, assets that are still at risk are analyzed in more detail as part of the Asset Integrity process.

	CLIMATE RISKS		CLIMATE OPPORTUNITIES
LOW CARBON SCENARIO	• Uncertainty about market development for new products • Changing consumer preferences (e.g. decline of global demand for hydrocarbons) • Loss of earnings and cash flow	RESOURCE EFFICIENCY & ENERGY SOURCE	• Energy efficiency and emission reduction measures with the adoption of Best Available Technology • Cost reduction through efficient water resource and waste management • Using sustainable raw materials for
	• Stranded asset risk • Impacts on shareholders' returns		biorefineries and chemistry
	• Introduction of new climate disclosure requirements		• Development of renewables and low carbon energy, CCS, and biochemistry/circular economy
REGULATORY AND LEGAL ISSUES	• Uncertainty about evolving regulatory frameworks with potential impacts on long-term strategy • Proceedings relating to climate change and greenwashing	PRODUCTS AND SERVICES	• Development of new products and services through R&D and open innovation (e.g. magnetic fusion)
TECHNOLOGICAL DEVELOPMENTS	• Profitability and specific risks of transition technologies • Delays in technology development and technology supply chain needed to meet decarbonization targets	MARKETS	• Partnerships for the development of technological solutions to cut emissions • Access to financing through sustainable finance instruments
	• Failure to address technologies that are important for the energy transition		• Access to new capital through the satellite model
REPUTATION	• Changing consumer preferences • Deterioration of the sector's image in the face of accusations of greenwashing • Deterioration of industry/company appeal for talent attraction & retention	RESILIENCE	• Design of climate change resilient assets through scenario studies and processes for monitoring physical risks
	• Impact on share price • Lower attractiveness of the sector to investors/financiers and potential disinvestment risk
ACUTE AND CHRONIC PHYSIQUES	• Possible effects on the operability and security of Eni's assets

Governance

Role of the BoD. Eni's decarbonization strategy is an integral part of Eni's business strategy, implemented through a structured system of Corporate Governance, where the BoD and the CEO play a central role in managing key climate change issues. Specifically, the BoD examines and approves the Strategic Plan proposed by the CEO, which sets out strategies and targets, including those related to climate change and energy transition, and, starting in 2019, examines and approves also Eni's medium/long-term plan, which aims to outline and monitor the evolution of decarbonization objectives and their economic and business sustainability in a time frame up to 2050.

Moreover, the BoD evaluates Eni's economic and financial exposure to carbon pricing risk in the preliminary phase to approve individual investments and monitor the subsequent project portfolio every six months. Annually, the BoD is informed about the impairment test result performed on the main Cash Generating Units that considers the International Energy Agency (IEA) Net Zero Emissions (NZE) scenario. Finally, the Board is notified quarterly about the outcomes of Eni's risk assessment and top risks monitoring, including climate change risk.

Since 2014, the Eni BoD has been supported in performing its duties by the Sustainability and Scenarios Committee (SSC), established on a voluntary basis, which, among other tasks, periodically examines the integration between strategy, development scenarios and the medium/ long-term sustainability of the business with a view to energy transition and climate change. During 2023, the SSC reviewed various topics related to climate change, including R&D activities for the energy transition, carbon pricing systems, agri-feedstock activities, Nature & Technology based carbon offsets, Eni's positioning on climate targets and strategies versus peers, Eni's performance in CDP questionnaires, climate resolutions and Shareholders' Meeting disclosures, Carbon Capture and Storage (CCS) projects, and Just Transition related topics.

Concerning the Board composition, based on the self-assessment, about 90% of the Board Members expressed their positive opinion on the professionalism within the Board – in terms of knowledge, experience, and skills (with particular reference to advisory, training and publication activities in the energy and environmental field, participation in governmental and non-governmental, national and international bodies that deal with these issues) – and on the personal contribution that the individual Board Members make to the Board of Directors in matters of sustainability, ESG and energy transition. These topics have characterized the work of the new Board since the start of its mandate, including through targeted training initiatives.

Role of management. All company structures are involved in the definition or implementation of the carbon neutrality strategy, reflected in Eni's organizational structure with the two business groups: Natural Resources, active in the optimization and progressive decarbonization of the Upstream portfolio, Natural Climate Solutions initiatives and CO2 storage projects, and Energy Evolution, active in the expansion of bio, renewable and circular economy activities and the offering of new energy solutions and services.

Since 2019, issues related to climate strategy and long-term planning have been managed by the CFO area through dedicated structures overseeing the process of defining Eni's decarbonization strategy and the related portfolio of initiatives. The strategic commitment to reducing carbon footprint is part of the Company's essential goals, and it is, therefore, reflected in the Variable Incentive Plans for the CEO and Company's management. In particular, the Long-Term Stock-based Incentive Plan, in line with the previous one, includes specific decarbonization, energy transition, and circular economy targets, with a total weight of 35%, consistent with the objectives communicated to the market and aiming to align with the interests of all stakeholders. The Short-Term Incentive Plan, in line with the previous one, is closely linked to Eni's strategic transformation objectives, including decarbonization and energy transition objectives consistent with the Long-Term Incentive Plan, with an overall weight of 25% for the CEO and, according to weights consistent with the responsibilities assigned, for all Company management.

Sensitivity of Oil & Gas asset book values to stress-test scenarios

Our portfolio of oil and gas properties features a large weight of natural gas, the least GHG-emitting fossil energy source. As of December 31, 2023, natural gas proved reserves represented approximately 52% of Eni's total proved reserves of its subsidiary undertakings and joint ventures. The other constituencies of our portfolio of oil&gas properties which are mitigating the risk of stranded assets are the large weight of conventional projects, featuring low CO2 intensity, and a low Brent price of breakeven. We estimate our reserves to have an average breakeven price that is fairly lower than current Brent crude oil prices (this estimation includes our proved reserves and a certain amount of unproved reserves), thus underpinning a rapid pay-back period.

The low breakeven price of our reserves has been driven by our exploration and development model that features: i) organic reserve replacement by means of effective exploration, which has been focused on near-field and proven/mature plays to leverage on existing infrastructures to readily put new reserves into production and to reduce development expenses; ii) a focus on low-complexity developments; and iii) a phased approach to putting reserves into production featuring early production start-up and subsequent ramp up to reduce the financial exposure of development projects and accelerate the timeto-market and the pay-back period. Based on those drivers, we have gradually reduced the breakeven price of our reserves and improved the resilience to low-carbon scenarios, which also considering the emissive profiles of our assets are expected to mitigate the risk of stranded reserves going forward. The risk of stranded assets might emerge in case of a structural decline in hydrocarbons demands because of the transition risks described in previous paragraphs.

Eni's portfolio exposure to those risks is reviewed annually against changing GHG regulatory regimes, evolving consumers' preferences, technological developments, and physical conditions to identify emerging risks.

As part of such review, the management stress-tested the recoverability of the book values of the Company's oil & gas assets of the 2023 financial statements by applying the assumptions set forth in the IEA Net Zero "NZE 2050" scenario and other lowered price assumptions, without assuming any management's actions on capex rescheduling, reduction or curtailments, cost revisions or other possible measures to adapt the business to a changed trading environment. The purpose of those stress tests is to evaluate the reasonableness of the outcome of the impairment review of those assets that is regularly performed by the management utilizing its own oil pricing, costs and other assumptions and considering proved reserves and certain amounts of unproved reserves, "the base case", as well as possible risks of stranded assets that could emerge within transition pathways that are faster than those forecast by the managements. Those stress tests covered the whole of the oil & gas cash generating units (CGUs) that are regularly tested for impairment in accordance with IAS 36. The stress test performed by Eni's management of the values-in-use of Eni's oil&gas assets under the pricing and cost assumptions of the IEA NZE scenario highlighted a loss of value and potential asset write-downs, all of which were not material based on management's judgement. Overall, the stress test confirmed the overall resilience of Eni's assets. Those stress tests have been performed by updating pricing and CO2 cost assumptions in management's cash flow projections and do not assume any change to all other factors in the models used, such as cost levels, volumes, and the discount rate, to calculate recoverability of carrying amounts. Sensitivity testing has been performed by applying the alternative commodity price scenarios to cash flows for the whole period until the end of life of the assets tested.

The results of those stress-tests are disclosed in "Item 18 - Note 15 to the Consolidated Financial Statements".

Strategy and Objectives

For "Strategy and Objectives" see paragraph above.

Key performance indicators

			2023	2022	2021
		Total (a)	of which fully consolidated entities	Total	Total
GHG EMISSIONS
Direct GHG emissions (Scope 1)	(million tonnes CO2eq)	38.69	21.53	39.39	40.08
Direct GHG emissions (Scope 1) by type of source
of which: CO2 equivalent from combustion and process		28.67	18.62	29.77	30.58
of which: CO2 equivalent from flaring		6.81	2.39	6.71	7.14
of which: CO2 equivalent from venting of which: CO2 equivalent from methane fugitive emissions		3.04 0.17	0.45 0.08	2.72 0.20	2.12 0.24
Carbon efficiency index (Scope 1 and 2)	(tonnes CO2eq/kboe)	31.90	48.79	32.67	31.95
Direct GHG emissions (Scope 1)/100% operated hydrocarbon gross production (upstream)		20.69	21.72	20.64	20.19
Direct GHG emissions (Scope 1)/Equivalent electricity produced (EniPower)	(gCO2eq/kWheq)	389.0	388.7	392.9	379.6
Direct GHG emissions (Scope 1)/Refinery throughputs	(tonnes
(raw and semi-finished materials)	CO2eq/ktonnes) )	232	232	233	228
Direct methane emissions (Scope 1) of which: fugitive upstream	(ktonnes CH4	39.1 6.0	16.6 2.0	49.6 7.2	54.5 9.2
Upstream methane emission intensity	(%)	0.06	n.a.	0.08	0.09
Volumes of hydrocarbon sent to flaring	(billion Sm3 )	2.1	n.a.	2.1	2.2
of which: Upstream routine		1.0	n.a.	1.1	1.2
Indirect GHG emissions (Scope 2)	(million tonnes CO2eq)	0.73	0.52	0.79	0.81
Indirect GHG emissions (Scope 3) from use of sold
products(b)		174	n.a.	164	176
Net GHG Emissions (Scope 1+2+3)(c)		200	n.a.	194	210
ENERGY
Electricity produced from renewable sources(d)	(GWh)	4,242	3,624	2,836	1,166
Primary source consumption	(millions of GJ)	497.5	316.2	484.4	529.1
of which: natural/fuel gas		413.9	237.1	395.1	429.0
of which: other primary sources		83.6	79.1	89.3	100.1
Primary energy purchased from other companies		17.1	13.4	17.6	21.7
of which: Electricity		15.0	11.3	15.1	18.3
of which: Other sources(e)		2.0	2.0	2.5	3.4
Hydrogen consumption		1.6	1.6	1.3	1.7
Total energy consumption		516.2	331.1	503.2	552.5
Energy consumption from renewable sources		1.3 0.1	1.3	1.2	1.5
of which: electricity from photovoltaics of which: biomass		1.2	0.1 1.2	0.03 1.1	0.6 0.9
Export of electricity to other companies		192.7	173.2	177.8	183.0
Export of heat and steam to other companies		5.2	4.7	5.7	5.4
Energy Intensity Index (refineries)	(%)	123.0	123.0	115.5	116.4
Energy consumption from production activities/ 100% operated hydrocarbon gross production (upstream)	(GJ/toe)	1.45	n.a.	1.41	1.45
Net consumption of primary resources/ Equivalent electricity produced (EniPower)	(toe/MWheq)	0.16	0.16	0.18	0.16
PRODUCTION OF BIOFUELS
Sold production of biofuels	(ktonnes)	635	n.a.	428	585
R&D
R&D expenditures	(€ million)	166	166	164	177
of which: related to decarbonization		135	135	114	114
Patent applications first filings(f)	(number)	28	28	23	30
of which: related to renewable energy sources		14	14	13	11

(a) Unless otherwise indicated, the KPIs related to emission and consumption refer to data 100% of operated/cooperated assets. Direct GHG emissions (scope 1) cooperated that are related to the Upstream sector amount to approx. 15.4 million tons.

(b) Category 11 of GHG Protocol – Corporate Value Chain (Scope 3) Standard. Estimates based on sales of upstream (Eni's share) production in line with IPIECA methodologies (O&G non-profit association for environmental and social issues).

(c) Net Carbon Footprint Eni (Scope 1+2) plus indirect GHG emissions (Scope 3) from the use of sold products. Data accounted for on an equity basis.

(d) In line with the company's strategic objectives, this indicator is reported on an equity basis. This KPI represents Eni's share and relates primarily to Plenitude.

(e) Includes steam, heat and hydrogen.

(f) The 2023 data relating to the patent application first filings, total and from renewable sources, include the contribution of the company Novamont for a total of 9, all relating to renewable sources.

Key target indicators ¹

		2023	2022	2021	Target
Net Carbon Footprint upstream (Scope 1+2)	(million tonnes CO2eq)	8.9	9.9	11.0	UPS Net zero @2030
Net Carbon Footprint Eni (Scope 1+2)		26.1	29.9	33.6	Eni Net zero @2035
Net GHG Lifecycle Emissions (Scope 1+2+3)		398	419	456	Net zero @2050
Net Carbon Intensity (Scope 1+2+3)	(gCO2eq./MJ)	65.6	66.3	66.5	Net zero @2050
Renewable installed capacity(a)	MW	3,056	2,256	1,188	>15 GW @2030
	(million				>5 million tonnes/year
Capacity of biorefineries	tonnes/year)	1.65	1.10	1.10	@2030

(a) This KPI represents Eni's share and relates primarily to Plenitude.

1 Indicators accounted for on an equity basis.

Significant business and portfolio developments

• March 2024 Eni received the authorization, through Development Consent Order (DCO), from the UK Government's Department for Energy Security and Net Zero (DESNZ) to build, operate and maintain the HyNet North West CO² pipeline to transport captured CO² as part of the HyNet CCS cluster.
• March 2024 Finalized the sale to Perenco of Eni's participation interest in several upstream permits in Congo, noncore to the Company strategy in the Country, after having obtained the approval of relevant authorities.
• March 2024 Plenitude and Energy Infrastructure Partners (EIP) finalized the agreement for EIP to enter Plenitude's share capital through a capital increase of €0.6 billion, equal to 7.6% of the Company's share capital.
• March 2024 Exploration activities yielded positive results with the Murene 1X exploration well on the Calao discovery in the CI-205 block (Eni's interest 90%), in Côte d'Ivoire.
• February 2024 First shipment of LNG from the Republic of Congo, thanks to the Congo LNG project, sanctioned in December 2022, came on stream after just 1 year, in line with the initial timeline.
• February 2024 Plenitude started operations at the new Ravenna Ponticelle photovoltaic plant. The plant has an installed capacity of 6 MW, covers an industrial area of 11 hectares and comprises over 10,000 photovoltaic panels.
• February 2024 Successful completion of the Cronos-2 well, drilled to appraise the Cronos discovery in Block 6, offshore Cyprus.
• January 2024 The Neptune Energy Group acquisition was finalized. The transaction, comprising Neptune's entire portfolio other than its operations in Norway (purchased by Vår Energi owned at 63% by Eni) and Germany (carved out of the transaction).
• January 2024 Confirmed the decision to build Italy's third bio-refinery in Livorno.
• January 2024 Eni obtained ISO 37301:2021 certification of its Compliance Management System from RINA Services SpA, Italy's leading certification body.
• January 2024 Started building a new high-performance computing (HPC) system, HPC6, which aims at significantly increasing the computational power of HPC4 and HPC5.

• January 2024 Signed a Letter of Intent between Enilive and Ryanair for the long-term supply of sustainable aviation fuel at selected Ryanair airports across Italy.

• January 2024 Gela biorefinery signed an agreement with Municipality of Gela for the launch of the Multipurpose Centre Macchitella Lab.

• January 2024 launched a bond, for a total nominal amount of €1 billion under its existing Euro Medium Term Note Programme. The 10-year Bond has a re-offer price of 99.277% and will pay an annual coupon of 3.875% which will remain unchanged to maturity. The proceeds of the bonds issue will be used for general corporate purposes. The bonds will be traded on the Luxembourg Stock Exchange.
• December 2023 Plenitude has signed an agreement with EDP Renováveis, S.A., to purchase an 80% equity stake in a portfolio of operational photovoltaic plants (Cattlemen, Timber Road and Blue Harvest) located in the United States.
• December 2023 Plenitude has reached an agreement with BlueFloat Energy and Sener Renewable Investments to join their strategic partnership to advance the development of offshore wind projects in Spain.
• December 2023 GreenIT has signed an agreement with Galileo, the pan-European renewable energy development and investment platform, for the realization of eight photovoltaic, across three regions in Southern, Central and Northern Italy.
• December 2023 signed a voluntary 5-year-term cooperation agreement with the International Organization for Migration (IOM) to boost youth employment in Libya's Fezzan region.
• December 2023 Eni Rovuma Basin (ERB) announced the beginning of production of vegetable oil which will be used as feedstock in Eni's biorefineries. This initiative is part of Eni's strategy to contribute to the decarbonization of transportation, and it will include Mozambique in the value chain of sustainable mobility.
• December 2023 Started the distribution of improved cookstoves to families in Rwanda, starting from the Nyagatare district. The initiative has the target to supply and monitor 500,000 improved cookstoves during the next 10 years to reduce CO2 emissions and improve health conditions while cooking
• December 2023 In the occasion of COP28, Eni has announced its membership as a donor to the Global Flaring and Methane Reduction trust fund (GFMR), an initiative launched by the World Bank to support governments and operators in developing countries to eliminate routine flaring and reduce methane emissions from the O&G sector to near zero by 2030.
• December 2023 Eni has signed a five-year Sustainability-Linked revolving credit line worth €3 billion, related to two targets of Eni's Sustainability-Linked Financing Framework, last updated in April 2023. The margin of the new credit line is linked to the achievement of sustainability targets relating to Net Carbon Footprint Upstream (Scope 1 and 2), as well as to the installed capacity for the production of electricity from renewable sources.

• December 2023 Eni announces that it has received a Gold Standard within the Oil and Gas Methane Partnership 2.0 (OGMP 2.0) program as reported today in the International Methane Emissions Observatory (IMEO) published by the United Nations Environment Programme (UNEP).

• November 2023 Eni and Swiss company Open Energy Platform AG (Open EP) signed an agreement to guarantee the flow of gas to Switzerland and Italy in the event of interruptions or significant flow reductions from Germany. The agreement will be effective from December 2, 2023 until September 30, 2024. During this period, the Swiss authorities will not adopt any restrictive measures on Eni's rights to gas transportation through Switzerland.

• November 2023 Plenitude signed an agreement with Saipem to install a photovoltaic system with a capacity of about 1 MW at Saipem's offices in Fano, Italy. The system solar power generation capacity will be able to meet almost all the energy needs of Saipem while improving its energy efficiency and overall sustainability.
• November 2023 Eni signed an agreement with Saipem, finalized to the study and subsequent potential construction of plants for the production of biojet, a sustainable aviation fuel, and of the biofuel HVO diesel, produced from 100% renewable raw materials. The agreement involves the application of Eni's proprietary Ecofining™ technology.
• October 2023 Versalis has begun the construction of a demo plant in Mantua to develop Hoop®, its proprietary technology for chemical recycling of mixed plastic waste.
• October 2023 Eni and the UK Government reached an agreement in principle on the key terms and conditions for the economic, regulatory and governance model for the transportation and storage of CO² at the HyNet North West industrial CCS cluster.
• October 2023 Dogger Bank, the world's largest offshore windfarm in which Vårgrønn holds a 20% stake, produced power for the first time, transmitted to the UK's national grid.
• October 2023 Eni signed a 0.8 bcm/year LNG sales and purchase agreement with Merakes LNG Sellers, starting from January 2024 for 3 years. This agreement, in addition to the contract with Jangkrik LNG Sellers for 1.4 bcm/year, in place since 2017, expands the overall LNG available from Bontang facility.
• October 2023 Eni signed a long-term contract with Qatar Energy LNG NFE (5), the JV between Eni Qatar Energy; for the development of the North Field East (NFE) project in Qatar, for the delivery of up to 1.5;bcm/year of LNG. LNG will be delivered at the receiving terminal "FSRU Italia", currently located in Piombino, Italy, with expected deliveries starting from 2026 with a duration of 27 years.
• October 2023 Versalis completed the purchase of the remaining 64% participating interest in Novamont from its other shareholder Mater-Bi.
• October 2023 Eni signed a Letter of Intent with the pharmaceutical company Dompé to launch joint research and development activities focusing on the health of people and communities in the areas where Eni operates, as well as other relevant global health issues.

• October 2023 Eni announced the important gas discovery at Geng North-1, an exploration well drilled in the North Ganal PSC, off Indonesia, with a preliminary estimated discovered volume of 5 trillion cubic feet (tcf) of gas and 400 mmbbl condensate in place.

• September 2023 Eni UK has been awarded a Carbon Dioxide Appraisal and Storage Licence (CS Licence) for the depleted Hewett gas field, in the Southern North Sea sector of the UK.

• September 2023 Eni signed with the Marine XII JV in Congo a purchase contract for LNG volumes from the Congo LNG project of up to approximately 4.5 bcm/year starting from December 2023. The project and the relative offtakes will have two phases: in the first phase the Tango FLNG facility will have a liquefaction capacity of 0.9 bcm/year, then a second FLNG with a capacity of 3.6 bcm/year will begin production in 2025.
• September 2023 Plenitude inaugurated its first photovoltaic plant in the Republic of Kazakhstan, with a 50 MW installed capacity. The photovoltaic plant will produce up to around 90 GWh of electricity annually.
• September 2023 Enilive and LG Chem, South Korea's leading chemical producer, announced the beginning of an evaluation of the development and operation of a new biorefinery at LG Chem's Daesan chemical complex, located Southwest of Seoul. The biorefinery is envisaged as having a capacity of around 400 ktonnes of organic raw materials per year and would use Eni's Ecofining™ technology.
• September 2023 Eni signed an agreement with the local partner Oando PLC (Nigeria's leading indigenous energy solutions provider) to divest Eni' subsidiary Nigerian Agip Oil Company Ltd (NAOC Ltd), with onshore oil & gas exploration and production activities, as well as the ancillary power generation business. The agreement does not include Eni's interest in the SPDC JV.
• September 2023 Versalis signed an agreement with Technip Energies, aimed at integrating Versalis' Hoop® and Technip Energies' Pure.rOilTM and Pure.rGasTM purification technologies by developing a technological platform for the advanced chemical recycling of plastic waste.
• August 2023 Eni started the production at Baleine oilfield, off the Côte d'Ivoire, demonstrating a rapid time-tomarket, less than two years after the discovery and less than a year and a half after the Final Investment Decision. The gas production will be delivered to the national grid, enabling the country to meet its domestic electricity requirements, facilitating energy access, and strengthening its role as a regional energy hub for neighboring countries.
• July 2023 Vårgrønn, a joint venture between Plenitude and HitecVision, and the Irish renewable-focused integrated utility Energia Group, signed a partnership to co-develop offshore wind projects in Ireland with a potential to deliver total capacity up to 1.8 GW by 2030.
• July 2023 GreenIT, a JV owned by Plenitude and CDP Equity, signed an agreement with Hive Energy Limited and SunLeonard Energy Limited to support the development of four photovoltaic projects with a total capacity of up to 200 MW. The new sites will be developed in Apulia, Sicily, and Lazio leveraging agri-voltaic technology, installing raised structures to achieve synergy between agriculture and the production of renewable energy.

• July 2023 Eni acquired Chevron's development and production assets in offshore Indonesia. The operation will ensure the fast-track development of ongoing projects in the area and the integration with Neptune Energy assets. This acquisition is also in line with Eni's energy transition strategy to increase the share of natural gas production to 60% by 2030. The closing of the transaction is subject to the customary governmental and regulatory approvals.

• June 2023 Plenitude finalized the acquisition from Helios UK (Spain) Ltd of a portfolio comprising two photovoltaic plants with a total capacity of 96.4 MWp in Spain's Albacete.

• June 2023 The new Plenitude's first utility-scale size battery plant of Assemini (Cagliari) realized in Italy started operations. The plant, with an installed capacity of 15 MW and an energy storage capacity of 9 MWh, has been realized with battery modules based on Lithium Iron Phosphate (LFP) technology.
• June 2023 Eniliveand PBF Energy Inc. (PBF) finalized the 50-50 joint venture partnership in St. Bernard Renewables LLC (SBR), an operating biorefinery co-located with PBF's Chalmette Refinery in Louisiana (USA). The biorefinery started operations in June and is currently targeted to have processing capacity of about 1.1 mln tonnes/year of raw materials, with full pretreatment capabilities. It will produce mainly HVO Diesel using the Ecofining™ process developed by Eni in cooperation with Honeywell UOP.
• June 2023 Eni signed with Perenco the agreement for the sale of its participating interest in several production licences in Congo.
• June 2023 Eni and its associate Vår Energi ASA have signed a sale and purchase agreement to acquire Neptune, a leading independent exploration and production company with global, low emission, gas-oriented operations, which also retains several projects for CO² capture. Eni will acquire an asset portfolio which features strong complementarity at both operational and strategic level with its own, strengthening the presence in key geographic areas, like UK, Algeria, Indonesia and Australia. Vår will consolidate its position in Norway.
• June 2023 Eni and KazMunayGas (KMG) announced a joint project for a 250 MW Hybrid Renewables-Gas Power Plant in Zhanaozen, in the Mangystau Region. The project, the first of its kind in the country, comprises a solar power plant, a wind power plant and a gas power plant for the production and supply of low-carbon and stable electricity to KMG subsidiaries in the area.
• June 2023 Eni signed a Memorandum of Understanding with Libya to evaluate possible opportunities to reduce GHG emissions and develop sustainable energy in the country. Under the terms of the memorandum, Eni will work on reducing CO² emissions through the reduction of routine gas flaring, fugitive emissions and venting, as well as possible projects for the reduction of hard-to-abate sector emissions.
• June 2023 Plenitude through its subsidiary Be Charge signed an agreement with Ikea to provide the installation of 250 latest generation charging station, within the parking areas of stores and Ikea centers throughout the country.
• May 2023 Kenya Airways made its first flight, powered by Eni Sustainable Mobility's SAF (Sustainable Aviation Fuel). The conventional JetA1 fuel was blended with Eni Biojet produced by Livorno refinery by distilling the biocomponents produced in the Gela biorefinery

• May 2023 Eni signed a Memorandum of Understanding (MoU) with Sonangol to evaluate possible joint initiatives in the areas of energy transition, including agro-industrial supply chains for the production of low-carbon fuels, the valorization of biomass for agro-industrial applications and critical minerals.

• May 2023 Eni and the Ministry of Agriculture and Rural Development of Vietnam (MARD) signed in Hanoi a memorandum of understanding (MoU) to cooperate in identifying initiatives in the fields of agri-feedstock and carbon credit generation from nature-based carbon offset solution.

• May 2023 Eni signed a Memorandum of Intent (MoI) with the Government of Republic of Guiné Bissau to explore potential areas of collaboration in exploration, nature and technology-based climate solutions, agriculture, sustainability and health. Other areas of collaboration include the evaluation of exploration potential of the country's offshore area.
• May 2023 The European Commission and Cassa Depositi e Prestiti awarded more than €100 mln to Be Charge for the construction, by 2025, of a network of over 2,000 "ultra-fast" charging points, with a minimum power of 150 kW along the main European transport corridors involving eight European countries.
• May 2023 Eni offloaded the first LNG cargo from Egypt's Damietta liquefaction plant into Snam's new regasification terminal in Piombino, off Tuscany. This was followed the delivery of the first commercial cargo, from Algeria's Betihoua plant, in July.
• April 2023 Eni inaugurated the Congo LNG project, the country's first natural gas liquefaction project and one of Eni's core supply diversification initiatives.
• April 2023 Eni and SPP, the Slovakia's largest energy supplier, signed a Memorandum of Understanding (MoU) for a commercial cooperation in the gas and LNG sector, aimed at evaluating initiatives in the areas of trading and management of regasification and transportation capacities to secure and strengthen supplies of natural gas to the Slovak Republic
• April 2023 The FPSO Firenze sailed out from Dubai to the Baleine field in Côte d'Ivoire. The FPSO to be renamed Baleine upon its mooring has been refurbished and upgraded.
• April 2023 Eni signed agreements to sell biofuels to two of Italy's largest transport and logistics companies (Fercam and Spinelli).
• March 2023 The HyNet North West cluster, comprising five submissions, was confirmed by the UK Department for Energy Security and Net Zero (DESNZ) to have been granted public funds provided by the UK government to develop a carbon capture and storage hub to decarbonize hard-to-abate industrial businesses in North-West England. Furthermore, Eni recently submitted an application to the North Sea Transition Authority (NSTA) for a carbon storage license to exploit the Hewett depleted natural gas field, in the Southern British North Sea.
• March 2023 Enivibes, a venture participated in by Eni with an interest of 76%, was established with the goal of enhancing the market value of a proprietary technology called E-vpms® (Eni Vibroacoustic Pipeline Monitoring System) The technology is dedicated to the mission-critical monitoring of the integrity of pipelines transporting liquids.
• March 2023 GreenIT, a JV owned by Plenitude and CDP Equity (an Italian state agency), signed an agreement with Copenhagen Infrastructure Partners (CIP) to develop floating offshore wind projects in Latium and Sardinia.

For significant business and portfolio developments occurred from January 2023 to the beginning of March 2023 see also the Annual Report on Form 20-F 2022 filed to SEC on April 5, 2023.

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, labour 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 35 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 2023, Eni average daily production amounted to 1,529 KBOE/d on an available-for-sale basis. As of December 31, 2023, Eni's total proved reserves amounted to 6,414 mmBOE; proved reserves of subsidiaries totaled 4,842 mmBOE; Eni's share of reserves of equity-accounted entities was 1,572 mmBOE. Profit per barrel of oil equivalent was 8.58 \$/bbl² (compared to 21.07 \$/bbl in 2022 and 13.66 \$/bbl in 2021).

"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 estimate 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 Platt's Marketwire, 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.

² 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.

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 rules³ . 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.

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 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 companies⁴ .

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 Eni⁵ .

In 2023⁶ , Ryder Scott Company and Sproule, for consolidated subsidiaries, and DeGolyer and MacNaughton, for equity accounted entities, provided an independent evaluation of approximately 34%⁷ of Eni's total proved reserves at December 31, 2023, confirming, as in previous years, the reasonableness of Eni internal evaluation. In the 2021-2023 three-year period, 77% of Eni total proved reserves were subject to an independent evaluation.

³ See "Item 19 – Exhibits" in the Annual Report on Form 20-F 2009.

⁴ For the past three years we have availed ourselves of the independent certification service of DeGolyer and MacNaughton, Ryder Scott, Societè Generale de Surveillance and Sproule.

⁵ In 2023 and 2022, Azule Energy and Vår Energi.

⁶ See "Item 19 - Exhibits".

⁷ Includes Eni's share of proved reserves of equity-accounted entities.

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, 2023, 2022 and 2021.

					Sub				Australia
		Rest of	North		Saharan		Rest of		and	Total
HYDROCARBONS (mmBOE) Consolidated subsidiaries	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	Americas	Oceania	reserves
Dec. 31, 2023(a)	374	60	964	694	809	933	733	238	37	4,842
developed	261	56	380	555	482	872	379	184	11	3,180
undeveloped	113	4	584	139	327	61	354	54	26	1,662
Dec. 31, 2022(b)	352	78	806	904	813	941	675	285	79	4,933
developed	271	73	329	655	460	881	383	207	43	3,302
undeveloped	81	5	477	249	353	60	292	78	36	1,631
Dec. 31, 2021	369	81	820	992	1,145	1,032	762	288	82	5,571
developed	283	80	373	852	766	963	445	203	51	4,016
undeveloped	86	1	447	140	379	69	317	85	31	1,555
Equity-accounted entities
Dec. 31, 2023(a)		425	8		494		378	267		1,572
developed		235	8		305			267		815
undeveloped		190			189		378			757
Dec. 31, 2022(b)(c)		473	9		531		383	285		1,681
developed		257	9		338			285		889
undeveloped		216			193		383			792
Dec. 31, 2021(d)		502	10		263			282		1,057
developed		261	10		39			282		592
undeveloped		241			224					465
Consolidated subsidiaries and equity accounted entities
Dec. 31, 2023(a)	374	485	972	694	1,303	933	1,111	505	37	6,414
developed	261	291	388	555	787	872	379	451	11	3,995
undeveloped	113	194	584	139	516	61	732	54	26	2,419
Dec. 31, 2022(b)	352	551	815	904	1,344	941	1,058	570	79	6,614
developed	271	330	338	655	798	881	383	492	43	4,191
undeveloped	81	221	477	249	546	60	675	78	36	2,423
Dec. 31, 2021	369	583	830	992	1,408	1,032	762	570	82	6,628
developed	283	341	383	852	805	963	445	485	51	4,608
undeveloped	86	242	447	140	603	69	317	85	31	2,020

(a) Effective January 1, 2023, Eni has updated the conversion rate of gas produced to 5,232 cubi 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. Prior-year converted amounts were left unchanged.

(b) Effective January 1, 2022, Eni has updated the conversion rate of gas produced to 5,263 cubic feet of gas equals 1 barrel of oil (it was 5,310 cubic feet of gas per barrel in previous reporting periods). The effect of this update on the change in the initial reserves balance as of January 1, 2022 amounted to 30 mmBOE. Prior-year converted amounts were left unchanged.

(c) Reserves volumes of the Sub-Saharan Africa area, in 2022, are affected by the derecognition of the Angolan companies transferred to the JV Azule Energy Holdings Ltd.

(d) Reserves volumes of the Sub-Saharan Africa area, in 2021, are affected by the change in the classification of the stake held in Mozambique Rovuma Venture SpA from joint operation to joint venture.

					Sub				Australia
		Rest of	North		Saharan		Rest of		and	Total
LIQUIDS (mmBBL)	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	Americas	Oceania	reserves
Consolidated subsidiaries
Dec. 31, 2023	211	27	384	139	334	637	485	213		2,430
developed	136	24	204	122	225	576	240	163		1,690
undeveloped	75	3	180	17	109	61	245	50		740
Dec. 31, 2022	188	36	364	167	367	644	433	234	1	2,434
developed	139	32	201	135	212	585	231	171	1	1,707
undeveloped	49	4	163	32	155	59	202	63		727
Dec. 31, 2021	197	34	393	210	589	710	476	237	1	2,847
developed	146	34	225	164	435	641	262	164	1	2,072
undeveloped	51		168	46	154	69	214	73		775
Equity-accounted entities
Dec. 31, 2023		326	6		207		110	26		675
developed		167	6		107			26		306
undeveloped		159			100		110			369
Dec. 31, 2022(a)		350	8		235		100	27		720
developed		173	8		135			27		343
undeveloped		177			100		100			377
Dec. 31, 2021		378	9		21			6		414
developed		175	9		9			6		199
undeveloped		203			12					215
Consolidated subsidiaries and
equity accounted entities
Dec. 31, 2023	211	353	390	139	541	637	595	239		3,105
developed	136	191	210	122	332	576	240	189		1,996
undeveloped	75	162	180	17	209	61	355	50		1,109
Dec. 31, 2022(a)	188	386	372	167	602	644	533	261	1	3,154
developed	139	205	209	135	347	585	231	198	1	2,050
undeveloped	49	181	163	32	255	59	302	63		1,104
Dec. 31, 2021	197	412	402	210	610	710	476	243	1	3,261
developed	146	209	234	164	444	641	262	170	1	2,271
undeveloped	51	203	168	46	166	69	214	73		990

(a) Reserves volumes of the Sub-Saharan Africa area, in 2022, are affected by the derecognition of the Angolan companies transferred to the JV Azule Energy Holdings Ltd.

					Sub				Australia
		Rest of	North		Saharan		Rest of		and	Total
NATURAL GAS (BCF) Consolidated subsidiaries	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	Americas	Oceania	reserves
Dec. 31, 2023	859	174	3,034	2,901	2,479	1,546	1,303	131	192	12,619
developed	653	167	919	2,262	1,350	1,546	725	107	58	7,787
undeveloped	206	7	2,115	639	1,129		578	24	134	4,832
Dec. 31, 2022	869	223	2,323	3,881	2,341	1,560	1,281	264	408	13,150
developed	695	214	670	2,732	1,306	1,560	796	195	223	8,391
undeveloped	174	9	1,653	1,149	1,035		485	69	185	4,759
Dec. 31, 2021	918	247	2,272	4,152	2,953	1,705	1,522	274	428	14,471
developed	729	242	781	3,656	1,759	1,705	971	210	266	10,319
undeveloped	189	5	1,491	496	1,194		551	64	162	4,152
Equity-accounted entities
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
Dec. 31, 2022(a)		646	9		1,562		1,490	1,355		5,062
developed		444	9		1,070			1,355		2,878
undeveloped		202			492		1,490			2,184
Dec. 31, 2021(b)		654	10		1,285			1,460		3,409
developed		457	10		165			1,460		2,092
undeveloped		197			1,120					1,317
Consolidated subsidiaries and equity accounted entities
Dec. 31, 2023	859	689	3,048	2,901	3,980	1,546	2,709	1,391	192	17,315
developed	653	526	933	2,262	2,386	1,546	725	1,367	58	10,456
undeveloped	206	163	2,115	639	1,594		1,984	24	134	6,859
Dec. 31, 2022(a)	869	869	2,332	3,881	3,903	1,560	2,771	1,619	408	18,212
developed	695	658	679	2,732	2,376	1,560	796	1,550	223	11,269
undeveloped	174	211	1,653	1,149	1,527		1,975	69	185	6,943
Dec. 31, 2021(b)	918	901	2,282	4,152	4,238	1,705	1,522	1,734	428	17,880
developed	729	699	791	3,656	1,924	1,705	971	1,670	266	12,411
undeveloped	189	202	1,491	496	2,314		551	64	162	5,469

(a) Reserves volumes of the Sub-Saharan Africa area, in 2022, are affected by the derecognition of the Angolan companies transferred to the JV Azule Energy Holdings Ltd.

(b) Reserves volumes of the Sub-Saharan Africa area, in 2021, are affected by the change in the classification of the stake held in Mozambique Rovuma Venture SpA from joint operation to joint venture.

Table of Contents

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 totaled 2 mmBOE as of December 31, 2023 (5 and 34 mmBOE as of December 31, 2022 and 2021, respectively). Said volumes are not included in reserves volumes shown in the table herein.

		Subsidiaries		Equity-accounted entities
(mmBOE)	2023	2022	2021	2023	2022	2021
Revisions of previous estimates	303	(64)	42	9	152	216
Improved recovery		7	12		4
Extensions and discoveries	105	118	62		61	8
Purchases of minerals-in-place	44	22	2	2	551
Sales of minerals-in-place	(58)	(228)	(5)	(1)	(49)
Total additions to proved reserves	394	(145)	113	10	719	224
Production for the year (a)	(485)	(493)	(526)	(119)	(95)	(88)

(a) The difference compared to production sold of 545.9 mmBOE (566.7 mmboe in 2021 and 532.0 mmboe in 2022) reflected hydrocarbons volumes of 58.2 mmBOE consumed in operations, changes in inventories and other factors (47.3 mmBOE in 2021 and 55.8 mmBOE in 2022).

	Subsidiaries and equity-accounted
		entities
(%)	2023	2022	2021
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all
sources	67	98	55
Proved reserves replacement ratio of subsidiaries and equity-accounted entities,
organic	69	47	55

Eni's proved reserves as of December 31, 2023 totaled 6,414 mmBOE (liquids 3,105 mmBBL; natural gas 17,315 BCF) and included the effect of updating the gas conversion factor (up by 21 mmBOE). Eni's proved reserves reported a decrease of 200 mmBOE, or 3% from December 31, 2022.

All sources additions to proved reserves booked in 2023 were 404 mmBOE; of which 394 mmBOE came from Eni's subsidiaries, while 10 mmBOE from Eni's equity-accounted entities.

The net effect of price changes was a positive 30 mmBOE in 2023 (of which a net positive revision of 27 mmBOE recorded at Eni's subsidiaries and a net positive revision of 3 mmBOE recorded at Eni's equity-accounted entities) due to lower Brent crude oil reference price used in the reserve estimation process of 83 \$/barrel in 2023, compared to 101 \$/barrel used in 2022. This price change led to the removal of reserves which have become uneconomical in the 2023 scenario (negative revision of 37 mmBOE recorded at Eni's subsidiaries and immaterial revisions were recorded at Eni's equity-accounted entities) more than offset by net higher reserves entitlements under PSA contracts (positive revision of 64 mmBOE recorded at Eni's subsidiaries and immaterial revisions were recorded at Eni's equity-accounted entities).

The methods (or technologies) used in Eni's proved reserves assessment in 2023 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 67% in 2023 (98% in 2022 and 55% in 2021). The organic reserves replacement ratio was 69% in 2023 (47% in 2022 and 55% in 2021) which excluded sales and purchases of minerals-in-place.

The all sources reserve replacement ratio during the three years ended December 31, 2023, which included a net increase of 280 mmBOE related to sales and purchases, was 73%.

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 10.6 years as of December 31, 2023, which included reserves of both subsidiaries and equity-accounted entities.

Eni's subsidiaries

Table of Contents

Eni's subsidiaries added 394 mmBOE of proved oil and gas reserves in 2023. Additions comprised an increase of 212 mmBBL of liquids and of 878 BCF of natural gas. The breakdown of total additions to proved reserves was the following: (i) revisions of previous estimates were positive for 303 mmBOE. The main positive revisions were in Bouri and Area D fields in Libya due to contractual changes and price effects, Val d'Agri field in Italy and M'boundi Gas field in Congo. The main negative changes were reported in Egypt mainly due to the reconfiguration of the Zohr project phase 2, which entailed a review of the compression design and a downward revision of the relevant reserves, and Blacktip field in Australia. Revisions also included net positive price effects of 27 mmBOE and the effect of an updating of the gas conversion factor (up 15 mmBOE); (ii) new discoveries and extensions of 105 mmBOE mainly as a result of the final investment decision at the Hail and Ghasha project in the United Arab Emirates, as well as the Merakes East project in Indonesia; (iii) purchase of minerals-in-place of 44 mmBOE and mainly related to the acquisition of bp assets in Algeria; and (iv) sales of minerals-in-place of 58 mmBOE mainly due to the sale of Alliance assets in the United States and a reduction in the stake at the Ghasha concession in the United Arab Emirates.

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 10 mmBOE of proved oil and gas reserves in 2023. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates were positive for 9 mmBOE. The main positive revisions were in the Coral South project in Mozambique. The main negative changes were in Azule Energy in Angola. Revisions also included net positive price effects of 3 mmBOE and the effect of an updating of the gas conversion factor (up 6 mmBOE); (ii) purchase of minerals-in-place of 2 mmBOE and related to the acquisition of an interest in the Block 3/05a by Azule Energy; (iii) sales of minerals-in-place of 1 mmBOE due to the divestment of the Brage field in Vår Energi in Norway.

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

Table of Contents

Proved undeveloped reserves as of December 31, 2023 totaled 2,419 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,109 mmBBL and of natural gas amounted to 6,859 BCF, mainly concentrated in Africa and Asia. Proved undeveloped reserves of consolidated subsidiaries amounted to 740 mmBBL of liquids and 4,832 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2023.

Subsidiaries and equity-accounted entities
(mmBOE)	2023
Proved undeveloped reserves as of December 31, 2022	2,423
Transfers to proved developed reserves	(187)
Extensions and discoveries	104
Revisions of previous estimates	121
Improved recovery
Portfolio	(42)
Proved undeveloped reserves as of December 31, 2023	2,419

During 2023, Eni matured 187 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 following fields/projects: Breidablikk, Fenja, Tommeliten Alpha, Bauge and Frosk in Vår Energi, Baleine in Côte d'Ivoire, Zohr in Egypt and Amoca in Mexico.

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 2023, capital expenditure amounted to approximately €9.1 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 Company estimates that 0.8 BBOE of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date and increased from 2022. The proved undeveloped reserves that have remained undeveloped for five years or more at the balance sheet date mainly related to: (i) certain Libyan gas fields (0.5 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force; (ii) Johan Castberg project for Vår Energi, the development of which is ongoing and first oil is expected in the last quarter of 2024 (0.1 BBOE); and (iii) other fields in Italy and Iraq (0.1 BBOE) where development activities are in progress; (iv) in the Umm Shaif (0.1 BBOE) reservoir in the United Arab Emirates where development is ongoing. (See also our discussion under the "Risk factors" section about risks associated with oil and gas development projects).

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

Table of Contents

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 612 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Ghana, Indonesia, Kazakhstan, Libya, 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 and supplies from third parties based on existing contracts. Production is expected to account for approximately 99.7% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2023.

Table of Contents

Oil and gas production, production prices and production costs

The matters regarding future production, additions to reserves and related production costs and estimated reserves discussed below and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni's important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni's production operations.

In 2023, oil and natural gas production available for sale averaged 1,529 KBOE/d (1,487 KBOE/d in 2022) and increased by 3% due to the ramp-up of the Coral FNLG project off Mozambique and of oil production at Area 1 off Mexico, the start-up of the Baleine project in Côte d'Ivoire, higher activity in Algeria, which also benefited from the business acquisitions, in Kazakhstan due to unplanned events occurred in 2022, as well as in Indonesia. These increases were offset by lower production due to mature fields decline.

Liquids production (768 KBBL/d) increased by 18 KBBL/d, or approximately 2% from the full year of 2022. Production growth in Kazakhstan and Côte d'Ivoire was partly offset by mature fields decline.

Natural gas production (3,980 mmCF/d) increased by 102 mmCF/d, or approximately 3% compared to the full year of 2022. Production increases were reported in Algeria, Mozambique in relation to the ramp-up of the Coral Floating LNG project, Indonesia and Kazakhstan, offset by mature fields decline.

Sales volumes of oil and gas production sold were 546 mmBOE. The 12 mmBOE difference over production on available-forsale basis (558 mmBOE in 2023) reflected mainly changes in inventory and other factors. Approximately 67% of liquids production sold (280 mmBBL) was destined to Eni's downstream. About 14% of natural gas production sold (1,394 BCF) was destined to Eni's Global Gas & LNG Portfolio segment.

The tables below provide Eni subsidiaries and its equity-accounted entities' production (annual volumes and daily averages), by final product marketed of liquids and natural gas by country and geographical area of each of the last three fiscal years.

Table of Contents

Average daily production available for sale (a)

		2023 (b)			2022 (c)		2021
		Natural			Natural			Natural
	Liquids	gas	Hydrocarbons Liquids		gas	Hydrocarbons Liquids		gas	Hydrocarbons
		(KBBL/d) (mmCF/d)	(KBOE/d)		(KBBL/d) (mmCF/d)	(KBOE/d)		(KBBL/d) (mmCF/d)	(KBOE/d)
Eni consolidated
subsidiaries
Italy	29	178	63	36	208	76	36	218	77
Rest of Europe	18	98	37	20	113	42	19	106	39
United Kingdom	18	98	37	20	113	42	19	106	39
North Africa	123	797	276	122	641	244	124	607	238
Algeria	62	249	110	62	96	81	54	85	70
Libya	59	540	162	58	536	159	67	510	163
Tunisia	2	8	4	2	9	4	3	12	5
Egypt	67	1,242	305	77	1,337	331	82	1,403	346
Sub-Saharan Africa	84	329	147	139	361	207	198	351	265
Angola				52		52	91		91
Congo	36	106	56	40	145	68	44	91	62
Côte d'Ivoire	4	1	4
Ghana	14	76	29	16	76	30	20	77	34
Nigeria	30	146	58	31	140	57	43	183	78
Kazakhstan	114	216	154	87	168	119	101	199	138
Rest of Asia	85	354	153	78	345	143	80	372	150
China	1		1	1		1	1		1
Indonesia	1	343	66	1	271	52	1	269	51
Iraq	23		23	15		15	24		24
Pakistan					50	10		53	10
Timor Leste		7	2	1	17	4	1	40	9
Turkmenistan	6		6	4		4	6		6
United Arab Emirates	54	4	55	56	7	57	47	10	49
Americas	68	45	76	59	54	69	53	55	63
Mexico	22	13	24	14	9	15	11	13	14
United States	46	32	52	45	45	54	42	42	49
Australia and Oceania		36	7		50	10		82	16
Australia		36	7		50	10		82	16
	588	3,295	1,218	618	3,277	1,241	693	3,393	1,332
Eni share of equity
accounted entities
Angola	85	74	100	36	63	49	3	74	17
Mozambique	1	88	18		6	1
Norway	87	244	133	89	274	141	111	297	167
Tunisia	2		2	3		2	3	1	3
Venezuela	5	279	58	4	258	53	2	238	47
	180	685	311	132	601	246	119	610	234
Total	768	3,980	1,529	750	3,878	1,487	812	4,003	1,566

(a) It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 127, 124 and 116 KBOE/d in 2023, 2022 and 2021, respectively

(b) 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. Prior-year converted amounts were left unchanged.

(c) Effective January 1, 2022, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,263 cubic feet of gas (it was 1 barrel of oil = 5,310 cubic feet of gas). The effect of this update on production was 8 KBOE/d in the full year 2022. Prior-year converted amounts were left unchanged.

Table of Contents

Annual production available for sale (a)

	2023 (b)				2022 (c)		2021
		Natural			Natural		Natural
	Liquids	gas	Hydrocarbons Liquids		gas	Hydrocarbons Liquids		gas	Hydrocarbons
	(mmBBL)	(BCF)	(mmBOE)	(mmBBL)	(BCF)	(mmBOE)	(mmBBL)	(BCF)	(mmBOE)
Eni consolidated
subsidiaries
Italy	10	65	23	13	76	28	13	80	28
Rest of Europe	7	36	13	7	41	15	7	39	14
United Kingdom	7	36	13	7	41	15	7	39	14
North Africa	45	291	100	45	234	89	45	221	87
Algeria	23	91	40	23	35	30	20	31	26
Libya	21	197	59	21	196	58	24	186	59
Tunisia	1	3	1	1	3	1	1	4	2
Egypt	24	453	111	28	488	121	30	512	126
Sub-Saharan Africa	31	120	54	51	132	76	73	128	96
Angola				19		19	33		33
Congo	13	39	20	15	53	25	16	33	22
Côte d'Ivoire	2		2
Ghana	5	28	11	6	28	11	8	28	13
Nigeria	11	53	21	11	51	21	16	67	28
Kazakhstan	41	79	56	32	61	43	37	73	51
Rest of Asia	31	129	56	28	126	52	29	136	55
China
Indonesia		125	24		99	19		98	19
Iraq	9		9	6		6	9		9
Pakistan					18	3		19	4
Timor Leste		3	1		7	1	1	15	3
Turkmenistan	2		2	2		2	2		2
United Arab Emirates	20	1	20	20	2	21	17	4	18
Americas	25	17	28	22	20	25	19	20	23
Mexico	8	5	9	5	3	5	4	5	5
United States	17	12	19	17	17	20	15	15	18
Australia and Oceania		13	3		18	4		30	6
Australia		13	3		18	4		30	6
	214	1,203	444	226	1,196	453	253	1,239	486
Eni share of equity accounted entities
Angola	31	27	36	13	23	18	1	27	6
Mozambique		32	7		2	1
Norway	32	89	49	33	100	51	41	109	61
Tunisia	1		1	1		1	1		1
Venezuela	2	102	21	1	95	19	1	87	17
	66	250	114	48	220	90	44	223	85
Total	280	1,453	558	274	1,416	543	297	1,462	571

(a) It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 46.2, 45.1 and 42.4 mmBOE in 2023, 2022 and 2021, respectively.

(b) 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 2023. Prior-year converted amounts were left unchanged.

(c) Effective January 1, 2022, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,263 cubic feet of gas (it was 1 barrel of oil = 5,310 cubic feet of gas). The effect of this update on production expressed in boe was approximately 3 mmBOE for the full year of 2022. Prior-year converted amounts were left unchanged.

Table of Contents

Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 33 KBOE/d, 35 KBOE/d and 43 KBOE/d in 2023, 2022 and 2021, 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.

(\$)

2021

					Sub				Australia
Consolidated subsidiaries	Italy	Rest of Europe	North Africa	Egypt	Saharan Africa	Kazakhstan	Rest of Asia	Americas	and Oceania	Total
Oil and condensates, per BBL	61.26	70.60	68.03	63.53	69.12	66.92	68.39	61.93	58.76	66.91
Natural gas, per KCF	15.47	15.75	6.42	4.74	4.32	0.54	6.21	4.06	4.25	5.93
Total hydrocarbons, per BOE	72.42	78.48	51.51	34.18	58.24	49.37	51.48	55.66	23.03	49.82
Average production cost, per BOE 13.74		12.35	7.91	3.74	10.00	4.96	5.43	14.72	3.52	7.39
Equity-accounted entities
Oil and condensates, per BBL		66.72	17.89		44.41			57.75		65.1
Natural gas, per KCF		15.11	5.83		14.68			4.32		10.71
Total hydrocarbons, per BOE		71.19	18.69		70.02			24.99		61.11
Average production cost, per BOE		7.53	7.36		4.71			0.99		6.00
2022
Consolidated subsidiaries
Oil and condensates, per BBL	67.07	93.94	92.11	87.64	103.96	86.94	94.13	92.03	60.89	92.41
Natural gas, per KCF	20.32	30.22	10.52	5.5	4.99	0.69	10.57	6.48	4.10	8.61
Total hydrocarbons, per BOE	87.98	128.03	73.29	42.64	83.12	64.59	76.85	83.45	22.25	69.07
Average production cost, per BOE 14.77		13.15	5.75	4.22	12.12	5.85	6.56	17.05	6.15	7.94
Equity-accounted entities
Oil and condensates, per BBL		97.51	17.82		85.71			88.39		92.97
Natural gas, per KCF		31.02	9.67		33.79			4.76		19.87
Total hydrocarbons, per BOE		121.12	19.31		108.43			29.27		98.29
Average production cost, per BOE		11.58	7.57		14.15			1.32		9.86
2023
Consolidated subsidiaries
Oil and condensates, per BBL	67.76	72.77	72.62	71.09	81.79	72.71	80.19	75.30	54.02	74.87
Natural gas, per KCF	13.67	14.44	9.44	5.47	5.36	0.74	10.38	3.22	4.16	7.28
Total hydrocarbons, per BOE	69.80	74.31	60.64	37.98	60.51	54.01	69.03	68.89	22.11	56.23
Average production cost, per BOE 16.36		16.21	5.57	4.22	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

Development well activity

In 2023, a total of 165 development wells were drilled (83.6 of which represented Eni's share) as compared to 187 development wells drilled in 2022 (71.1 of which represented Eni's share) and 154 development wells drilled in 2021 (47.7 of which represented Eni's share).

The drilling of 76 development wells (27.6 of which represented Eni's share) is currently underway.

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 s tatus of the Company's development wells in the process of being drilled as of December 31, 2023. 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.

		Wells in progress at 31 Dec.
(units)	2023	2022			2021		2023
	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy	1.0		1.0				2.0	1.2
Rest of Europe	4.8		4.6		4.8		16.0	2.2
North Africa	9.3		5.7	0.5	2.5		6.0	3.9
Egypt	30.1		19.9		17.0	0.8	9.0	6.8
Sub-Saharan Africa	5.6		8.5		3.8		13.0	4.5
Kazakhstan	2.0		0.6				1.0	0.3
Rest of Asia	22.9		22.1		14.9		27.0	7.7
Americas	6.9		8.2		3.9		2.0	1.0
Australia and Oceania	1.0
Total including equity
accounted entities	83.6		70.6	0.5	46.9	0.8	76.0	27.6

Exploration well activity

In 2023, a total of 39 new exploratory wells were drilled (21.6 of which represented Eni's share), as compared to 40 exploratory wells drilled in 2022 (18.9 of which represented Eni's share) and 31 exploratory wells drilled in 2021 (17.4 of which represented Eni's share).

The overall commercial success rate was 34.5% (38% net to Eni) as compared to 45% (44% net to Eni) and 54% (49% net to Eni) in 2022 and 2021, 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, 2023. 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."

Exploratory Well Activity

Table of Contents

	Net wells completed						Wells in progress at Dec. 31
(units)	2023		2022		2021		2023
	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy
Rest of Europe	0.1	0.4	0.4	1.2	0.1	0.3	31.0	7.8
North Africa		1.6	1.0	4.0			9.0	6.0
Egypt	5.0	4.6	4.4	4.3	5.0	5.0	10.0	7.4
Sub-Saharan Africa	0.3	0.9	3.7	2.4	1.1	0.4	35.0	17.5
Kazakhstan
Rest of Asia	0.9	1.3	0.7	1.0	0.7	1.0	15.0	6.8
Americas		1.4				0.7	4.0	2.3
Australia and Oceania							1.0	0.3
Total including equity
accounted entities	6.3	10.2	10.2	12.9	7.0	7.4	105.0	48.1
			51

Oil and gas properties, operations and acreage

In 2023, Eni performed its operations in thirty-five countries located in five continents. As of December 31, 2023, Eni's mineral right portfolio consisted of 744 exclusive or shared rights of exploration and development oil and gas activities. Total acreage amounts to 301,308 square kilometers net to Eni (total acreage was 308,550 square kilometers net to Eni as of December 31, 2022). Developed acreage was 27,069 square kilometers and undeveloped acreage was 274,239 square kilometers net to Eni.

In 2023 new leases were purchased or awarded in Egypt, Timor Leste, Indonesia, Algeria, Norway, Angola, the United Kingdom and Côte d'Ivoire for a total increase in acreage of approximately 21,400 square kilometers. Relinquishment for the year related mainly to Kenya, Vietnam, Indonesia, Gabon, Egypt, Algeria, Mozambique, Lebanon and Norway covering an acreage of approximately 31,800 square kilometers. Interest increases were reported mainly in Kenya, Indonesia, Mexico, and Norway for a total acreage of approximately 7,200 square kilometers. Partial relinquishment was reported mainly in Algeria, the United Arab Emirates, Indonesia, Côte d'Ivoire, Mexico, Italy, Egypt and Lebanon for approximately 4,100 square kilometers.

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 propertyspecific, 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 and Albania; (ii) Rest of Asia, in particular in Oman, Vietnam, Indonesia and the United Arab Emirates; (iii) North Africa, in particular in Morocco, Libya and Egypt; (iv) Sub-Saharan Africa, in particular in Kenya, Angola, Côte d'Ivoire and Mozambique; and (v) Americas, in particular in Mexico. In most cases extension or renewal options are contractually defined and may or may not be exercised depending on the results of the studies and the planned activities. Management believes that a significant amount of acreage will be maintained following extension or renewal.

The table below provides certain information about the Company's oil&gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2023. A gross acreage is one in which Eni owns a working interest.

	December 31, 2022	December 31, 2023
	Total net acreage (a)	Number of interests	Gross developed acreage (a)(b)	Gross undeveloped acreage (a)	Total gross acreage (a)	Net developed acreage (a)(b)	Net undeveloped acreage (a)	Total net acreage (a)
EUROPE	33,632	296	13,340	57,973	71,313	7,774	27,472	35,246
Italy	10,884	111	7,556	4,809	12,365	6,378	4,052	10,430
Rest of Europe	22,748	185	5,784	53,164	58,948	1,396	23,420	24,816
Albania	587	1		587	587		587	587
Cyprus	13,988	7		25,474	25,474		13,988	13,988
Norway	6,686	142	4,838	25,339	30,177	763	7,398	8,161
United Kingdom	1,487	35	946	1,764	2,710	633	1,447	2,080
AFRICA	117,396	297	51,139	226,691	277,830	14,098	99,144	113,242
North Africa	43,080	92	15,269	105,698	120,967	6,360	35,872	42,232
Algeria	8,720	65	10,010	8,067	18,077	3,919	3,953	7,872
Libya	24,644	14	1,963	78,085	80,048	958	23,686	24,644
Morocco	7,529	1		16,730	16,730		7,529	7,529
Tunisia	2,187	12	3,296	2,816	6,112	1,483	704	2,187
Egypt	7,103	53	4,851	29,187	34,038	1,706	10,721	12,427
Sub-Saharan Africa	67,213	152	31,019	91,806	122,825	6,032	52,551	58,583
Angola	6,516	83	10,927	34,958	45,885	912	6,721	7,633
Congo	1,299	19	971	1,320	2,291	586	713	1,299
Côte d'Ivoire	4,000	7	1,658	2,865	4,523	1,382	2,578	3,960
Gabon	2,931
Ghana	495	3	226	930	1,156	100	395	495
Kenya	41,892	3		35,724	35,724		35,724	35,724
Mozambique	3,868	7	719	7,803	8,522	180	3,080	3,260
Nigeria	6,212	30	16,518	8,206	24,724	2,872	3,340	6,212
ASIA	145,585	52	10,389	253,595	263,984	3,540	137,031	140,571
Kazakhstan	1,947	7	2,391	3,853	6,244	442	1,505	1,947
Rest of Asia	143,638	45	7,998	249,742	257,740	3,098	135,526	138,624
China	10	2	43		43	7		7
Indonesia	12,106	12	3,252	16,505	19,757	2,092	10,036	12,128
Iraq	446	1	1,074		1,074	446		446
Lebanon	1,461	1		1,742	1,742		610	610
Oman	58,955	3		102,016	102,016		58,955	58,955
Qatar	38	1		1,206	1,206		38	38
Timor Leste Turkmenistan	1,928 180	5 1	412 200	6,232	6,644 200	122 180	5,838	5,960 180
United Arab
Emirates	18,662	12	3,017	29,603	32,620	251	17,579	17,830
Vietnam	28,633	4		23,908	23,908		21,251	21,251
Other Countries
(c)	21,219	3		68,530	68,530		21,219	21,219
AMERICAS	9,186	95	2,152	14,332	16,484	1,023	8,475	9,498
Mexico	3,107	10	34	5,198	5,232	34	3,408	3,442
United States	654	73	857	280	1,137	492	139	631
Venezuela	1,066	6	1,261	1,543	2,804	497	569	1,066
Other Countries	4,359	6		7,311	7,311		4,359	4,359
AUSTRALIA AND OCEANIA	2,751	4	728	2,608	3,336	634	2,117	2,751
Australia	2,751	4	728	2,608	3,336	634	2,117	2,751
Total	308,550	744	77,748	555,199	632,947	27,069	274,239	301,308

(a) Square kilometers

Table of Contents

(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, 2023 and by main producing countries in each geographic area, Eni's producing assets, the year in which Eni's activities started, the Eni's participating interest in each asset and whether Eni is operator of the 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 83 licenses (of which 56 development licenses and 27 exploration licenses) relating to 20 blocks (of which 5 exploration blocks) and also in the Angola LNG JV; (ii) in Norway, the Vår Energi associate (Eni's interest 63.1%) holds interests in 142 licences (of which 83 development licenses and 59 exploration licenses); (iii) in Mozambique, the Mozambique Rovuma Venture SpA joint venture (Eni's interest 35.71%) is the operator of the Area 4 production licence; (iv) 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; and (v) in Tunisia, where operate the Société Italo Tunisienne d'Exploitation Pétrolière (Eni's interest 50%) and Sodeps (Eni's interest 50%) joint ventures.

Table of Contents
ITALY	(1926)	Operated	Adriatic and Ionian Sea: Barbara (100%), Annamaria (100%), Clara NW (51%), Hera Lacinia (100%) and Bonaccia (100%) Basilicata Region: Val d'Agri (61%) Sicily: Gela (100%), Tresauro (75%), Giaurone (100%), Fiumetto (100%), Prezioso (100%) and Bronte (100%)
REST OF EUROPE United Kingdom	(1964)	Operated	Liverpool Bay (100%)
		Non-operated	Elgin/Franklin (21.87%), Glenelg (8%), J Block (33%), Jasmine (33%) and Jade (7%)
NORTH AFRICA
Algeria (a)	(1981)	Operated	Sif Fatima II (49%), Zemlet El Arbi (49%), Ourhoud II (49%), Blocks 403a/d (from 65% to 100%), Block ROM North (35%), Blocks 401a/402a (100%), Block 403 (50%), Block 405b (75%), Berkine South (75%), In Amenas (45.89%) and In Salah (33.15%)
		Non-operated	Block 404-208 (17.5%)
Libya (a)	(1959)	Operated	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%) Offshore contract areas: Area C (Bouri - 50%) and Area D (Block NC 41 - 50%)
Tunisia	(1961)	Operated	Maamoura (49%), Baraka (49%), Adam (25%), Oued Zar (50%) and Djebel Grouz (50%)
EGYPT (a)(b)	(1954)	Operated	Shorouk (Zohr - 50%), Nile Delta (Abu Madi West/Nidoco - 75%), Sinai (Belayim Land, Belayim Marine, Abu Rudeis and Sinai Ras Gharra - 100%), Meleiha (76%), North Port Said (Port Fouad - 100%), Temsah (Tuna, Temsah and Denise - 50%), Southwest Meleiha (75%), Baltim (50%), North El Hammad Offshore (Bashrush - 37.5%) and East Obayed (Faramid - 75%).
		Non-operated	Ras el Barr (Ha'py and Seth - 50%) and South Ghara (25%).
SUB-SAHARAN AFRICA
Congo	(1968)	Operated	Néné-Banga Marine and Litchendjili (Block Marine XII, 65%), Ikalou (85%), Djambala (50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%) and M'Boundi (83%).
		Non-operated	Yanga Sendji (29.75%) and Likouala (35%).
Côte d'Ivoire	(2015)	Operated	Baleine (77.25%)
Ghana	(2009)	Operated	Offshore Cape Three Points (44.44%)
Nigeria	(1962)	Operated	OMLs 60, 61, 62 and 63 (20%) and OML 125 (100%)
		Non-operated (c)	OML 118 (12.5%)
KAZAKHSTAN (a)	(1992)	Operated (d)	Karachaganak (29.25%)
		Non-operated	Kashagan (16.81%)
REST OF ASIA
Indonesia	(2001)	Operated	Jangkrik (55%) and Merakes (65%)
Iraq	(2009)	Non-operated (e)	Zubair (41.56%)
Turkmenistan	(2008)	Operated	Burun (90%)
United Arab Emirates	(2018)	Non-operated	Lower Zakum (5%), Umm Shaif and Nasr (10%) and Area B - Sharjah ( 50%)
AMERICAS Mexico	(2019)	Operated	Area 1 (100%)
United States	(1968)	Operated	Gulf of Mexico: Allegheny (100%), Appaloosa (100%), Pegasus (100%), Longhorn (75%), Devils Towers (100%) and Triton (100%)
		Non-operated	Alaska: Nikaitchuq (100%) and Oooguruk (100%) Gulf of Mexico: Europa (32%), Medusa (25%), Lucius (14.45%), K2 (13.4%), Frontrunner (37.5%) and Heidelberg (12.5%)

(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 include 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 SPDC JV, Eni holds a 5% interest in 16 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks.

(d) Eni and Shell are co-operators.

(e) 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.

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, 2023. 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 7,373 (2,534.5 of which represent Eni's share).

Productive oil and gas wells at Dec. 31, 2023 (a)

(units)	Oil Wells		Natural gas Wells
	Gross	Net	Gross	Net
Italy	130.0	117.2	327.0	289.4
Rest of Europe	456.0	78.7	226.0	47.9
North Africa	644.0	292.1	260.0	123.5
Egypt	1,093.0	499.1	150.0	51.3
Sub-Saharan Africa	2,297.0	387.5	174.0	24.5
Kazakhstan	211.0	57.7	1.0	0.3
Rest of Asia	1,030.0	370.9	100.0	41.4
Americas	257.0	143.1	14.0	6.9
Australia and Oceania			3.0	3.0
Total including equity-accounted entities	6,118.0	1,946.3	1,255.0	588.2

(a) Multiple completion wells included above: approximateley 997 (303.2 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 oil revenues to the 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 of the foreign jurisdictions mainly in African, Middle Eastern, 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. 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).

A similar scheme applies to some Service contracts.

Eni's exploration and production activities are regulated by PSA or scheme similar 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 24 onshore and 48 offshore productive concessions. Exploration activities have been substantially abandoned in recent years. In 2023, Italy accounted for approximately 4% of Eni's total worldwide production of oil and natural gas.

In 2023, 30% of Eni's domestic production came from fields in the Adriatic and Ionian Seas, 49% from the Central Southern Apennines and approximately 13% from Sicily.

In the gas assets of the Adriatic and Ionian Seas, activities concerned: (i) maintenance and production optimization intervention at the Hera Lacinia, Luna and Naomi Pandora fields; and (ii) production start-up of the Donata field. Decommissioning plan to plug-and-abandon depleted wells and remove non-productive platforms progressed during the year in compliance with Italian Ministerial Decree 15 February 2019 "Linee guida nazionali per la dismissione mineraria delle piattaforme per la coltivazione in mare e delle infrastrutture connesse". The decommissioning process is ongoing for 10 platforms in compliance with the above-mentioned Decree. In addition, campaign to plug-and-abandon non-productive onshore and offshore wells is ongoing.

In the Val d'Agri concession, activities carried out during the year concerned: (i) sidetrack of existing wells, mainly in the Monte Enoc area, based on the approved "Work Program"; and (ii) production optimization activities to mitigate field decline.

The construction activities of the Argo and Cassiopea project (Eni's interest 60%) have progressed. During 2023, the installation of the sealine transporting the gas from the offshore well to the onshore treatment facilities was completed. The onshore plant construction is ongoing and approaching completion foreseen in the second quarter of 2024. Natural gas production start-up is expected in the first half of 2024.

In Italy a plan (PiTESAI) aiming to identify areas suitable for exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters, was adopted on December 28th, 2021.

Following the above plan, exploration permits are confirmed only for the part located in "suitable" areas and withdrawn otherwise.

As far as development concessions are concerned, no significant impacts are recorded for Eni's petroleum activities in the Country. See "Regulation of Eni's businesses".

In order to boost the national gas production and mitigate the gas price effect on the economy, the Italian Government issued a first Decree (D.L. Energia) on March 1st, 2022, which also mitigates the effects of PiTESAI. A second decree (D.L. Sicurezza Energetica), with the same target was issued on December 9th, 2023, providing the ground for new upstream development opportunities.

Following an appeal by Oil&Gas companies, PiTESAI was declared void by Lazio Administrative Court (TAR) on February 13, 2024. The reaction by the Government is still under evaluation.

Rest of Europe

Eni's operations in the Rest of Europe are mainly conducted in the United Kingdom and in Norway, in this latter country through Vår Energi. In 2023, the Rest of Europe accounted for 11% of Eni's total worldwide production of oil and natural gas.

Norway. In October 2023, production start-up was achieved at the Breidablikk project with the completion of the drilling activities and the linkage to the existing facilities in the area.

Main development activities concerned: (i) the Johan Castberg sanctioned project with start-up expected in 2024; and (ii) the Balder X sanctioned project in the PL 001 license, located in the North Sea. The Balder project scheme provides for drilling additional productive wells, to be linked to an upgraded Jotun FPSO unit that will be relocated in the area that will support the development of new discoveries near to the area through upgrading existing infrastructure. Production start-up is expected in 2024.

Vår Energi was awarded: (i) in February 2023, 12 exploration licenses, 5 of which are operated, following the "Awards in Predefined Areas 2022" (APA) by the Ministry of Petroleum and Energy of Norway; (ii) in February 2024, 16 exploration licenses, 4 of which are operated, following "2023 APA".

Exploration activities yielded positive results with: (i) the Countach oil and gas discovery in the Goliat PL 229 licence located in the Barents Sea; (ii) the Kim oil discovery in the PL 185 license in the North Sea; (iii) the Crino oil and gas discovery in the North Sea; (iv) the Norma gas discovery in the PL 984 in the North Sea; and (v) the Svalin M Sør oil discovery in the PL 169 license.

United Kingdom. Development activities mainly concerned: (i) the Talbot development project (Eni's interest 33%) with subsea tie-back to Judy field. First oil is expected at the end of 2024; and (ii) decommissioning planned activity of the Hewett Area

North Africa

Eni's operations in North Africa, with Egypt being discussed separately due to the size of Eni's reserves in the Country, are mainly conducted in Algeria, Libya and Tunisia. In 2023, North Africa accounted for 18% of Eni's total worldwide production of oil and natural gas.

Algeria. In 2023 the following agreements were finalized: (i) the purchase of 45.89% interest in the In Amenas concession and 33.15% interest in the In Salah concession; (ii) new contract for the block 404-208 with Eni's participating interest increasing to 17.5% (from 12.25%).

The development activities are as follows: (i) infilling program in several fields of 401a/402a blocks, Sif Fatima II, Ourhoud II and Zemlet El Arbi blocks as well as In Amenas and In Salah concessions; (ii) workover activities in 404-208, 405b and 403 blocks as well as the conversion of certain wells into water-alternate-gas (WAG) injectors in block 403; (iii) upgrading of the third treatment train of the BRN plant; (iv) drilling activities and linkage of infilling wells in Berkine South area together with debottlenecking of oil line. Furthermore, a 10 MW photovoltaic plant is under construction at the BRN field in the block 403, in addition to the 10 MW plant already completed in 2020. The construction plans for a 12 MW photovoltaic plant at the MLE field in the block 405b currently under evaluation.

Exploration activities have yielded positive results with the RODE-1 gas discovery in Sif Fatima II concession. Development activities are expected to start in 2024.

Libya. Currently, Libya represents approximately 11% of the Group's total production. In 2023, a relatively stabler sociopolitical environment than in previous years, allowed continuity to production operations creating a favorable backdrop for reaching agreements with the National Oil Company (NOC) for future development projects in the Country. Despite those developments, going forward, management believes that Libya's geopolitical situation will continue to represent a source of risk and uncertainty to Eni's operations in the Country and to the Group results of operations and cash flow. 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 2059 for Area D-new developments (A&E Structures).

In January 2023, Eni signed an agreement with NOC for the development of the large gas reserves of A&E Structures, to increase natural gas production to sustain the domestic market and export volumes to Europe. Production is expected to start in the next years. The project foresees an onshore Carbon Capture and Storage (CCS) hub as well, in line with Eni's decarbonization strategy. Furthermore, in May 2023, Eni signed an agreement with NOC to start the development of the Bouri Gas Utilization (BGUP) project. From a development standpoint the main activities in 2023 were: (i) the sanctioning of the A&E Structures project and following the award of EPCI contract for the WHPA platform; (ii) the sanctioning of the BGUP project to reduce CO² emissions and to valorize associated gas of the Bouri field; and (iii) the Sabratha Compression project to support current production of the Bahr Essalam field and additional production of the A Structure development program. During the year the relevant EPCI contract was awarded, and the project is currently in execution phase.

Furthermore, in June 2023, Eni signed a Memorandum of Understanding with Libyan Government of National Accord to evaluate possible opportunities to reduce GHG emissions and develop sustainable energy in the country, in line with Eni's strategy and Libyan government targets to accelerate in a decarbonization and transition energy programs.

Tunisia. Exploration activities yielded positive results with the Sabeh-01 and Wissal-01 wells in the Borj El Khadra exploration permit. Engineering studies are ongoing to define development scheme of the last discoveries wells with the Anbar-01 discovery well, drilled in 2022.

Egypt.

In 2023, Egypt accounted for 20% of Eni's total worldwide production of oil and natural gas, the largest contributor to the Company overall production level.

In January 2023, Eni signed a Memorandum of Intent (MoI) with EGAS to jointly study opportunities on GHG emissions reduction in the upstream sector in the Country through a plan of initiatives leading additional gas monetization.

In 2023 production start-up was achieved at the Faramid gas field in the Western Desert concession leveraging on the existing facilities and plants in the area.

Development activities of the Zohr production project concerned: (i) water shut-off program for gas production optimization; (ii) EPCI activities for the construction of a news subsea infrastructures; and (iii) development activities to increase water production treatment capacity by means of the facilities upgrading and the installation of two additional treatment units.

The rights of Eni to produce at the Zohr Development Lease will expire in 2037.

As of December 31, 2023, the aggregate development costs incurred by Eni for developing the Zohr project and capitalized in the financial statements amounted to \$6.2 billion (€5.6 billion at the EUR/USD exchange rate of December 31, 2023). Development expenditure incurred in the year were €230 million.

As of December 31, 2023, Eni's proved reserves booked at the Zohr field amounted to 480 mmBOE.

Development activities also concerned: (i) production optimization in the Sinai concession by means of new wells drilled and workover and water-injection programs; (ii) drilling and completion of an additional production well, already started up, in the Baltimo-Neho area; (iii) drilling of an additional well in the Nile Delta concession and the upgrading of the Nidoco NW transport facilities to the treatment plant with an increased production; and (iv) optimization gas production program in the Rasl el Barr concession leveraging on a new compression unit.

In addition, in the Western Desert concession development activities concerned: (i) the Meleiha Phase 2, in early production by 2022, by means of the installation of a new pipeline to existing treatment plant; and (ii) production optimization initiatives leveraging on the drilling program of additional production oil and gas wells.

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 activities yielded positive results with: (i) the Nargis 1X discovery in the East Med area (Eni's interest 45%); (ii) the two oil and gas discoveries in the Sinai and Nile Delta concessions, respectively; and (iii) the three oil exploration discoveries in the Western Desert concession.

Sub-Saharan Africa

Eni's operations in Sub-Saharan Africa are conducted mainly in Congo, Côte d'Ivoire, Ghana, Mozambique, Nigeria and Angola, in this latter trough Azule Energy. In 2023, Sub-Saharan Africa accounted for 17% of Eni's total worldwide production of oil and natural gas.

Angola. During 2023 Azule achieved an agreement to divest its interest and operatorship of the Cabinda Norte block.

In September 2023 Azule signed a Memorandum of Understanding with Sonangol to jointly collaborate in the decarbonization program in the country.

In March 2023 the Solenova JV, a solar company jointly owned by Azule and Sonangol, achieved solar energy production start-up at the 25 MW photovoltaic plant in Caraculo.

Development activities concerned: (i) start-up development activities of the Quiluma and Maboqueiro fields within the New Gas Consortium project. The project, first non-associated gas development in the country, provides for the installation of two offshore platform production, an onshore treatment plant and linkage facilities to A-LNG liquefaction plant. Production start-up is expected in 2026 with an estimated production plateau of approximately 330 mmcf/d; (ii) the Agogo Integrated West Hub project in the western area of the Block 15/06 was sanctioned. Main contracts were already awarded and production startup is expected in 2026 with an estimated production peak of 170 KBOE/d; (iii) optimization development studies progressed at the PAJ project in the Block 31; and (iv) development activities of the Cuica and Cabaça fields and the Ndungu early production project were completed in the Block 15/06. Production started up by means of the linkage to existing facilities in the area.

Exploration activities yielded positive results with the Lumpembe-1X oil exploration well in the block 15/06. Development studies are ongoing to possible integration with other discoveries in the southern area of the block. In addition, a five-year extension of exploration agreement was finalized.

Congo. In March 2024, Eni finalized with Perenco the sale of its participating interest in several production licences in the country.

In December 2023, the Congo LNG project was started up by means of the offshore installation of the Tango FLNG liquefaction plant, with a capacity of approximately 35 BCF/y, and the Excalibur Floating Storage Unit (FSU). Development plan includes the installation of two floating gas liquefaction units (FLNG), one LNG storage unit (FSU), seven new platforms, an onshore treatment plant and drilling of 41 wells. Main contracts were awarded. The second FLNG unit with a capacity of approximately 125 BCF/y is already under construction. Start-up is expected in 2025.

The project is expected to monetize the gas volumes of the Marine XII block for the country's energy needs and by exploiting the surplus gas for LNG production. Development activity is planned to also leverage on the existing assets, through modular and phased program. Liquefaction gas capacity is planned to achieve approximately 160 BCF/y at plateau. According to the agreements recently signed, all LNG production will be marketed by Eni.

Other development activities concerned the completion of the Néné Phase 2B project. In particular, drilling and completion activities of all planned production well were completed.

Exploration activities yielded positive results with the Poalvou Marine 2 gas and condensates and the Mbenga Marine 1 oil and gas discoveries in the Marine VI Bis (Eni 65%) permit. Both declarations of discovery were notified to the Ministry of Hydrocarbons.

Côte d'Ivoire. In August 2023, start-up production was achieved at the Baleine oilfield in the operated offshore CI-101 (Eni's interest 83%) and CI-802 (Eni's interest 76.9%) blocks. Management believes this field to contain a large amount of hydrocarbon.

Full field development includes two additional phases. The Phase 2 sanctioned program is expected to achieve first oil at the end of 2024. Main contracts for the additional facilities constructions were awarded while the drilling and completion of additional wells is expected to start up in 2024.

In March 2024 the successful exploration well Murene 1X led to the Calao Discovery in the block CI-205 (Eni's interest 90%).

Ghana. In the year development activities of the OCTP operated project concerned the completion of: (i) the upgrading activities of the facilities, FPSO unit and onshore gas plant to increase production capacity; (ii) water produced reinjection program; and (iii) additional activities to improve the power generation reliability of the gas-fired power plan.

Mozambique. Eni has been present in Mozambique since 2006, following the award of the exploration license relating to gas rich Area 4 offshore the Rovuma Block.

In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by TotalEnergies. In 2012, Eni made another large gas discovery at the Coral prospect, which falls entirely in Area 4. During the exploration period, which expired in 2015, six Discovery Areas (DA) were identified. Mozambique Decree Law 02/2014 provides that individual plans of development can be submitted in respect of each DA.

Under the Area 4 EPCC (Exploration and Production Concession Contract), each Plan of Development once approved by the Government of Mozambique entitles the Concessionaires to develop and to produce in a term of 30 years, with an extension option pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law. Following two separate transactions occurred respectively in 2013 and in 2017, Eni divested to CNPC and ExxonMobil indirect interests of 20% and 25% respectively in the discoveries of Area 4, by diluting its participating interest in Mozambique Rovuma Venture SpA, the operator of Area 4. Post transactions, Eni retains a 25% indirect interest in the Area 4 concession.

The other concessionaires of Area 4 are the state-owned oil company ENH, Galp and Kogas, each with a 10% working interest.

In 2017, the concessionaires of Area 4 made the final investment decision to develop the reserves of the Coral discovery, sanctioning the Coral South project.

The Coral South project is currently in production. The project provided for the installation of the Coral Sul Floating Liquefied Natural Gas (FLNG) vessel for the treatment, liquefaction, storage and export, with a capacity of approximately 3.4 mmtonnes/y of LNG, feed by six subsea wells.

Additional development phases to put into production the Area 4 reserves, are being evaluated by the delegated operators of Area 4 (Eni and ExxonMobil), which are expected to include offshore development options, based on the expertise achieved with the Coral South FLNG project, and onshore activities also through synergies with Area 1.

Nigeria. In September 2023, Eni signed an agreement with the local partner Oando PLC to divest Eni' subsidiary Nigerian Agip Oil Company Ltd (NAOC Ltd), with onshore oil and gas exploration and production activities, as well as the ancillary power generation business. The agreement does not include Eni's interest in the SPDC JV (Eni's interest 5%). Following the transaction completion with Oando PLC, Eni will continue to run activities in the country, focusing on its upstream operated offshore assets, not operated assets and midstream activities through its participation in Nigeria LNG Ltd.

Development activities concerned: (i) drilling and completion of one well to increase gas production in the Obiaafu field area in the OML 61 block; and (ii) drilling of one production wells and two injection wells at the Bonga field in the OML 18 block and the linkage to production facilities existing in the area.

Development activities of the SPDC joint venture production areas concerned: (i) drilling, completion, and start-up of seven oil production wells at the Ogbo and Tunu fields; (ii) completion and linkage of four production wells in the Forcados Yokri area; and (iii) production start-up of an additional gas well in the Gbaran area. In addition, during 2023, FID of the Epu Phase 2 project was sanctioned.

Eni holds also a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant has a production capacity of 22 mmtonnes/y of LNG associated with approximately 1,270 BCF/y of feed gas. Natural gas supplies to the plant are currently provided under a gas supply agreement from the SPDC JV, TEPNG JV and the NAOC JV (Eni's interest 20%). In 2023, the Bonny liquefaction plant processed approximately 740 BCF. LNG production is sold under long-term contracts and exported mainly to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG, as well as is sold FOB by means of the fleet owned by third parties.

Kazakhstan

Eni's operations in Kazakhstan comprised the Kashagan and the Karachaganak fields. In 2023, 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 2023, production at the Kashagan field averaged 70 KBBL/d of liquids and 60 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 of the Kashagan field 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 management capacity increase of associated gas with: (i) increasing gas reinjection capacity by means of upgrading the existing facilities. Activities were 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-time horizon, management does not expect any material impact on the Company's liquidity or its ability to fund these capital expenditures.

As of December 31, 2023, Eni's proved reserves booked for the Kashagan field amounted to 584 mmBOE.

As of December 31, 2023, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to \$10.2 billion (€9.2 billion at the EUR/USD exchange rate of December 31, 2023). This capitalized amount included: (i) \$7.5 billion relating to expenditures incurred by Eni for the development of the oil field; and (ii) \$2.7 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years. Cost incurred in the year were €63.6 million.

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 2023, production of the Karachaganak field averaged 44 KBBL/d of liquids and 156 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. 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.

During 2023 the additional development phase, sanctioned in 2020, of the Karachaganak field progressed and included: (i) the drilling of three new injection wells; (ii) the construction of a new sixth injection line; (iii) the installation of a fifth compression gas unit. Start-up is expected in 2024; and (iv) the installation of a sixth compression unit, last development phase, sanctioned in 2022. Start-up is expected in 2026.

As of December 31, 2023, Eni's proved reserves booked for the Karachaganak field amounted to 349 mmBOE.

As of December 31, 2023, the aggregate costs incurred by Eni for the Karachaganak project capitalized in the financial statements amounted to \$4.9 billion (€4.4 billion at the EUR/USD exchange rate of December 31, 2023). Cost incurred in the year were €224 million.

Rest of Asia

Eni's operations in the Rest of Asia are mainly conducted in Indonesia, Iraq, Turkmenistan and the United Arab Emirates. In 2023, Eni's operations in the Rest of Asia accounted for approximately 10% of its total worldwide production of oil and natural gas.

Indonesia. In 2023, Eni acquired Chevron's development and production assets in offshore Indonesia.

Development activities concerned: (i) the Merakes East project in the operated East Sepinggan block, in the deep offshore eastern Kalimantan; (ii) the Maha project in the operated West Ganal offshore block (Eni's interest 40%). Development activities were defined; and (iii) upgrading activities of the gas compression facilities in the operated Muara Bakau block.

Exploration activities yielded positive results with the Geng North-1 gas discovery, in the operated North Ganal offshore license (Eni's interest 50.22%). Management believes this field contains a large volume of hydrocarbons.

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. 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 drilling of infilling wells to maximize hydrocarbons recovery of the Burun field.

United Arab Emirates. In March 2023 Eni signed a Memorandum of Understanding (MoU) with ADNOC for future joint projects in the areas of energy transition, sustainability and decarbonization.

Development activities of the year concerned: (i) the Dalma Gas Development sanctioned project in the offshore Ghasha concession (Eni's interest 10%) and the Umm Shaif Long-Term Development Phase 1 sanctioned project in the Umm Shaif and Nasr concession (Eni's interest 10%); (ii) development project of the Hali and Ghasha fields in the Ghasha concession was sanctioned and two contracts for the planned construction of offshore facilities and onshore treatment plant were awarded; and (iii) studies for the development of the recent discoveries (2022) in the Block 2 (Eni operator with a 70% interest) are underway.

Americas

Eni's operations in Americas are conducted mainly in Mexico, United States and Venezuela. In 2023, Eni's operations in the Americas area accounted for approximately 9% of its total worldwide production of oil and natural gas.

Mexico. Development activities of the year concerned the last full field development phase of the operated Area 1 license. In particular, activities provide for the construction and installation of two additional platform in the Amoca and Tecoalli fields. In addition, ongoing drilling activities include the completion of planned wells to achieve production ramp-up.

Exploration activities yielded positive results with the Yatzil discovery in the Area 7 license (Eni operator with a 45% interest).

United States. Eni holds: (i) interests in 45 exploration and production blocks in the Gulf of Mexico, of which 15 as operator; and (ii) interests in 27 operated production blocks and interest in 1 non-operated block in Alaska.

In 2023 Eni finalized the divestment of its interests in the Alliance area in Texas.

Venezuela. In 2023, Eni's production of oil and natural gas averaged 58 KBOE/d and accounted for approximately 4% of Eni's total production. Eni's production comes mainly from the Perla gas field. Other petroleum interests held by Eni in the Country comprise the Corocoro field in the Gulf de Paria and the Junín 5 oil field in the Orinoco Oil Belt. These latter interests are immaterial to the Company. The operations in the Country have been negatively affected by a difficult operational environment mainly due to the deteriorated economic and financial outlook of the Country that has been made worse by the U.S. sanctions regime, thus limiting the ability of the Company to collect the revenues from the sale of its equity production at the Perla field. During 2023, the increase in receivables related to natural gas supplies in the period was partially offset by some in kind repayments through the allocation of PDVSA-owned crude oil cargoes which was also made possible due to a substantial improvement in the current sanction framework. However, there is still a great deal of uncertainty about any possible evolution of the US sanctions against Venezuela and Eni's ability to recover its outstanding receivables.

For further information on this matter, see "Item 3 — Risk factors – Political considerations".

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.

Global Gas & LNG Portfolio

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.

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 to both hedge and stabilize the Group commercial margins and optimize the gas asset portfolio. In 2023, Eni's worldwide sales of natural gas amounted to 50.51 BCM. Sales in Italy amounted to 24.40 BCM, while sales in European markets were 23.84 BCM that included 2.29 BCM of gas sold to certain importers to Italy.

The business results of operations in 2023 and its strategy are described in "Item 5 – Group results of operations" and "Item 5 – Management's expectations of operations."

Supply of natural gas

The supply contracts which were intended to support Eni's sales plan in Italy and in other European markets, provide take-or-pay clauses whereby the Company has an obligation to lift minimum, preset volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to a minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations which arise from contracts with transmission system operators or pipeline owners, which the Company has entered into to secure long-term transport capacity.

In 2023, Eni subsidiaries' total supply of natural gas was 50.05 BCM, decreased by 10.54 BCM, or 17.4% from 2022. Gas volumes supplied outside Italy (44.34 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 89% of total supplies, decreased by 12.85 BCM, or 23% compared to the previous year, due to lower volumes purchased in Russia (down by 11.04 BCM), in France (down by 1.28 BCM), in Egypt (down by 0.80 BCM), in the UK (down by 0.49 BCM), in Norway (down by 0.26 BCM) and Libya (down by 0.10 BCM), partially offset by higher purchases in Qatar (up by 0.35 BCM), in Netherlands (up by 0.23 BCM), in Algeria (up by 0.20 BMC) and in Indonesia (up by 0.20 BCM). Supplies in Italy (5.71 bcm) reported an increase of 68% from the full year 2022.

In 2023, main gas volumes from equity production derived from: (i) Eni fields located in the British and Norwegian sections of the North Sea (2.1 BCM); (ii) Italian gas fields (1.8 BCM); (iii) Indonesia (0.9 BCM); (iv) Libyan fields (0.6 BCM). Supplied gas volumes from equity production were approximately 5.4 BCM representing around 11% of total volumes available for sale.

The table below sets forth Eni's purchases of natural gas by source for the periods indicated.

Natural gas supply	2023	2022	2021
		(BCM)
Italy	5.71	3.40	3.59
Outside Italy	44.34	57.19	67.39
Russia	6.16	17.20	30.21
Algeria (including LNG)	12.06	11.86	10.12
Libya	2.52	2.62	3.18
the Netherlands	1.62	1.39	1.41
Norway	6.49	6.75	7.52
the United Kingdom	1.42	1.91	2.65
Indonesia (LNG)	1.56	1.36	1.81
Qatar (LNG)	2.91	2.56	2.30
Other supplies of natural gas	5.89	8.11	2.39
Other supplies of LNG	3.71	3.43	5.80
Total supplies of subsidiaries	50.05	60.59	70.98
Withdrawals from (input to) storage	0.54	0.00	(0.86)
Network losses, measurement differences and other changes	(0.08)	(0.07)	(0.04)
Volumes available for sale of Eni's subsidiaries	50.51	60.52	70.08
Volumes available for sale of Eni's affiliates	0.00	0.00	0.37
Total volumes available for sale	50.51	60.52	70.45

Sales of natural gas

Eni is selling gas to wholesale markets in Italy and in a number of European countries. The wholesale market includes sales to large accounts (industrials and thermoelectric utilities) and on European spot markets.

In 2023, natural gas sales amounted to 50.51 BCM (including Eni's own consumption, Eni's share of sales made by equityaccounted entities), representing a decrease of 10.01 BCM, or 16.5% from the previous year, due to lower sales in Italy, in Europe and outside Europe. Sales in Italy (24.40 BCM) decreased by 6.27 BCM or 20.4% from 2022, mainly due to lower volumes marketed in all business segments, mainly to hub and in the wholesale and industrial sectors. Sales in the European markets amounted to 21.55 BCM, decreased by 13.7% or 3.43 BCM from 2022.

Sales to long-term buyers were 2.29 BCM; down by 5.8% compared to the previous year due to the lower availability of Libyan output.

Sales in the Extra European markets (2.27 BCM) decreased by 0.17 BCM or 7% due to lower LNG sales 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 entities	2023	2022	2021
		(BCM)
Total sales of subsidiaries	50.51	60.52	69.99
Italy (including own consumption)	24.40	30.67	36.88
Rest of Europe	23.84	27.41	27.69
Outside Europe	2.27	2.44	5.42
Total sales of Eni's affiliates (Eni's share)	0.00	0.00	0.46
Rest of Europe	0.00	0.00	0.32
Outside Europe	0.00	0.00	0.14
Worldwide gas sales	50.51	60.52	70.45

Natural gas sales by market	2023	2022	2021
		(BCM)
ITALY	24.40	30.67	36.88
Wholesalers	10.71	12.22	13.37
Italian gas exchange and spot markets	6.28	9.31	12.13
Industries	1.50	2.89	4.07
Power generation	0.52	0.83	0.94
Own consumption	5.39	5.42	6.37
INTERNATIONAL SALES	26.11	29.85	33.57
Rest of Europe	23.84	27.41	28.01
Importers in Italy	2.29	2.43	2.89
European markets	21.55	24.98	25.12
Iberian Peninsula	2.75	3.93	3.75
Germany/Austria	3.35	3.58	0.69
Benelux	3.75	4.24	3.47
United Kingdom/Northern Europe	1.42	1.92	2.65
Turkey	6.90	7.62	8.50
France	3.31	3.62	5.80
Other	0.07	0.07	0.26
Extra European markets	2.27	2.44	5.56
WORLDWIDE GAS SALES	50.51	60.52	70.45

The LNG business

Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from: Qatar, Nigeria, Indonesia and Egypt. In the plan period, Eni intends to develop its LNG business leveraging on the integration with the E&P segment and the valorization of the equity gas. Final markets of that gas include Europe and Asia. The business's profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities.

LNG sales	2023	2022	2021
		(BCM)
Europe	7.3	7.0	5.4
Extra European markets	2.3	2.4	5.5
	9.6	9.4	10.9

International transport

Eni has transport rights on a large European network of integrated infrastructures for transporting natural gas, which links key consumption markets with the main producing areas (Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya). Eni has contracted the transport capacity under ship-or-pay contracts, which are similar to take-or-pay contracts.

The main assets of Eni's transport activities are provided in the table below.

International Transport infrastructure Route

		Total		Transport	Compression
	Lines	length	Diameter	capacity	stations
	(units)	(km)	(inch)	(BCM/y)	(No.)
	2 lines of
TTPC (Oued Saf Saf-Cap Bon)	km 370	740	48	34.3	5
	5 lines of
TMPC (Cap Bon-Mazara del Vallo)	155	775	20/26	33.5
	1 line of
GreenStream (Mellitah-Gela)	km 516	516	32	11.5	1
	2 lines of
Blue Stream (Beregovaya-Samsun)	km 387	774	24	16.0	1

International transport activities

The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometers long with a transport capacity of 34.3 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.

The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155 kilometers long with a transport capacity of 33.5 BCM/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.

In 2023, the Eni's subsidiaries managing the pipelines from Algeria through Tunisia to Italy have been divested to a newly established joint venture with Snam, where Eni retaing a 50.1% interest. The GreenStream pipeline, jointly-owned with the Libyan National Oil Corporation, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 516-kilometers long with a transport capacity of 11.5 BCM/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system.

The Blue Stream underwater pipeline (water depth greater than 2,150 meters) links the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.

See "Risks in connection with Russia's military aggression of Ukraine and the Middle East conflict in the Gaza strip" in the Risk factors section for further information.

Capital expenditures

See "Item 5 – Liquidity and capital resources – Capital expenditures by segment".

Enilive, Refining and Chemicals

Enilive and Refining

Competitive trends in the industries where the Company operates

Enilive

Enilive is facing strong competition in the marketing of fuels to retail customers due to low product differentiation and customers' sensitivity to prices at 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.

Refining

Eni's oil refining business is exposed to structural headwinds of the industry due to muted trends in the European demand for fossil fuels, with expectations of long-term decline due to market penetration of electric vehicles and growing supplies of biofuels, refining overcapacity with new additions expected to come online in the next years or to become operational shortly and continued competitive pressure from players in the Middle East, the United States and Far East Asia. Those competitors can leverage on larger plant scale and cost economies, availability of cheaper feedstock and lower energy expenses. Eni's refining business is incurring expenses for the purchase of allowances in connection with the emission of CO² in its operations to comply with the requirements of the European ETS, which reduce the competitiveness of Eni's fuels with respect to other jurisdictions that do not yet impose those charges to refiners.

Enilive is dedicated to 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 and biomethane. 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 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) such as gasoline, diesel fuel, biodiesel, LPG and lubricants.

The business results depend heavily on trends in refining margins, i.e. the spread between the cost of the oil feedstock and the price of the refined products obtained from the crude processing.

In 2023, the Standard Eni Refining Margin reported an average of 10.1 \$/barrel vs. 8.5 \$/barrel reported in the comparative period. Refining margins increased driven mainly by lower prices of natural gas. However, it is noted that under the current circumstances of narrowing differentials between heavy/sour crudes vs. lighter/sweet grades due to tight supplies of the former, the SERM does not entirely capture the effective refining margin.

The business results of operations in 2023 and its strategy are described in "Item 5 – Group results of operations" and "Item 5 – Management's expectations of operations".

Supply

In 2023, a total of 19.08 mmtonnes of crude were purchased (compared with 19.15 mmtonnes in 2022), of which 4.57 mmtonnes by equity crude oil. The breakdown by geographic area was the following: approximately 28% of purchased crude came from Central Asia, 19% from the Middle East, 14% from North Africa, 9% from Italy, 7% from North Sea, 5% from West Africa and 18% from other areas.

Refining

In 2023, Eni refinery capacity (balanced with conversion capacity) was approximately 26.4 mmtonnes (equal to 528 KBBL/d), with a conversion index of 47%. 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 18.4 mmtonnes (equal to 368 KBBL/d), with a 45% conversion index. In 2023, Eni's refineries throughputs in Italy and outside Italy were 18.88 mmtonnes. The average refinery utilization rate, ratio between throughputs and refinery capacity, is 77%.

	Ownership (%)	Balanced refining capacity (Eni's share) (1) (KBBL/d)	Utilization rate (Eni's share) (%)	Conversion index (2) (%)
Wholly-owned refineries		368	73	45
Italy
Sannazzaro	100	180	87	54
Taranto	100	104	66	56
Livorno	100	84	52	11
Partially owned refineries		160	86	51
Italy
Milazzo	50	100	98	60
Germany
Vohburg/Neustadt (Bayernoil)	20	41	63	36
Schwedt	8.33	19	75	34
Total		528	77	47

(1) Including 20% share in ADNOC Refining, balanced refining capacity amounted to 691 KBBL/d.

(2) Conversion index: catalytic cracking equivalent capacity/topping capacity (%wt).

Italy

Eni's refining system in Italy is composed of the wholly-owned refineries of Sannazzaro, Livorno and Taranto, as well as its 50% stake in the Milazzo refinery in Sicily. Eni's refineries operate to maximize asset value according to market conditions and the integration with marketing activities.

The Sannazzaro refinery has a balanced capacity of 180 KBBL/d and a conversion index of 54%. Located in the Po Valley, in the center of the Northern Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation.

The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 56%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy and is upstream integrated with the Val d'Agri (Eni 61%) and Tempa Rossa fields in Basilicata through a pipeline. The main equipments are a topping-vacuum unit, a residue hydrocracking and a gasoil hydrocracking unit, a platforming unit and two desulphurization units.

The Livorno refinery, with a balanced refining capacity of 84 KBBL/d and a conversion index of 11%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a topping-vacuum unit, a platforming unit, two desulphurization units and a de-aromatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and de-waxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.

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 equipments in the refinery are: 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).

Outside Italy

In Germany, Eni owns an interest of 8.33% stake 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.

	Ownership share	Capacity (2023)	Throughput (2023)
	(%)	(mmtonnes/y)	(mmtonnes/y)
Wholly-owned
Venezia	100	0.4	0.2
Gela	100	0.7	0.5
Partially owned refineries
Chalmette	50	0.55	0.2
Total biorefineries		1.65	0.9

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) start in 2025.

Since 2020 Gela biorefinery has been using the EcofiningTM conversion technology, developed by Eni, capable of converting vegetable oils and feedstock consisting of waste and residues, such as used cooking oils and animal fats, into HVO. The specifics of the plant, with a capacity of 0.7 million tons/year, together with a strong supply strategy, allow HVO to be produced in compliance with recent regulatory constraints in terms of reducing GHG emissions throughout the product life cycle. In March 2021, the Biomass Treatment Unit (BTU) was launched to expand the range of raw materials to be treated by the plant, allowing the processing of waste and residues such as animal fats and used cooking oil, replacing palm oil, which has not been used since the end of 2022. In the second half of 2024, the biorefinery will be upgraded to produce biojet (SAF).

In June 2023, Enilive and PBF Energy Inc. (PBF) finalized the 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 pretreatment capabilities. It mainly produces HVO Diesel using the Ecofining™ process developed by Eni in collaboration with Honeywell UOP.

The table below sets forth Eni's sales of refined products by distribution channel for the periods indicated.

Availability of refined products	2023	2022	2021
		(mmtonnes)
ITALY
Refinery throughputs
At wholly-owned refineries	13.31	13.25	14.01
Less input on account of third parties	(1.32)	(1.70)	(1.71)
At affiliated refineries	4.89	4.57	4.21
Refinery throughputs on own account	16.88	16.12	16.51
Consumption and losses	(1.17)	(1.11)	(1.11)
Products available for sale	15.71	15.01	15.40
Purchases of refined products and change in inventories	7.03	7.02	7.38
Products transferred to operations outside Italy	(0.43)	(0.40)	(0.67)
Consumption for power generation	(0.31)	(0.31)	(0.31)
Sales of products	22.00	21.32	21.80
Biorefinery throughputs	0.87	0.54	0.67
OUTSIDE ITALY
Refinery throughputs on own account	2.00	2.72	2.27
Consumption and losses	(0.17)	(0.19)	(0.18)
Products available for sale	1.83	2.53	2.09
Purchases of finished products and change in inventories	3.75	3.54	3.41
Products transferred from Italian operations	0.43	0.40	0.67
Sales of products	6.01	6.47	6.17
Refinery throughputs on own account	18.88	18.84	18.78
of which: refinery throughputs of equity crude on own account	4.57	5.02	3.86
Total sales of refined products	28.01	27.79	27.97
Crude oil sales	0.27	0.21	0.60
TOTAL SALES	28.28	28.00	28.57

In 2023, Eni's refining throughputs on own account in Europe were 18.88 mmtonnes, substantially in line with 2022.

In Italy, the refinery throughputs (16.88 mmtonnes) up by 4.7% from 2022 following higher volumes processed at the Taranto, Milazzo and Sannazzaro refineries following optimization initiatives, partially offset by higher standstills at the Livorno plant.

Outside Italy, Eni's refining throughputs on own account were 2 mmtonnes, down by approximately 0.72 mmtonnes or 26.5% due to plant unavailability at the Bayernoil refinery. Total throughputs in wholly-owned refineries were 13.31 mmtonnes, substantially in line with the comparative period (13.25 mmtonnes).

The refinery utilization rate, ratio between throughputs and refinery capacity, is 77%.

Approximately 24.4% of processed crude was supplied by Eni's Exploration & Production segment, representing a reduction from 2022 (26.8%).

In 2023, biorefineries throughput has been 0.87 mmtonnes, an increase of 0.33 mmtonnes compared to 2022 (up by 61%), thanks to higher volumes processed at Gela biorefinery and the Chalmette acquisition; these improvements more than offset lower Venice biorefinery throughput.

Logistics

Eni is a leading operator in the Italian oil and refined products storage and transportation business.

Oil and refined products are transported: (i) by sea through spot and long-term contracts of tanker ships; and (ii) inland through a proprietary pipeline and depots network directly operated.

In particular, Eni owns and operates an integrated infrastructure consisting of 15 directly managed depots and one managed through the subsidiary Petroven, 100% owned since December 2019.

Eni also owns a network of oil and refined products pipelines extending approximately 1,200 kilometers operating. Eni logistic model is organized in four operative management (Northern depots, Central depots, Southern depots and LPG and Pipeline) operating in handling and storage of the product flows in order to guarantee high safety, asset integrity and technical standards (HSE e asset integrity), as well as cost optimization and constant products availability along the country. Eni is also part of 7 different logistic joint ventures (Sigemi, Seram, Disma, Seapad, Toscopetrol, Porto Petroli Genova and Costiero Gas Livorno), together with other Italian operators, that operate other localized depots and pipelines.

Secondary distribution is outsourced to independent trucks, selected as market leaders.

Marketing

Enilive markets a wide range of refined petroleum products, primarily in Italy, through a widespread operated network of service stations, franchises, and other distribution systems.

The table below sets forth Eni's sales of refined products by distribution channel for the periods indicated.

Oil products sales in Italy and outside Italy	2023	2022	2021
		(mmtonnes)
Italy
Retail	5.32	5.38	5.12
Wholesale	6.45	6.19	6.02
	11.77	11.57	11.14
Petrochemicals	0.44	0.39	0.52
Other sales	9.79	9.36	10.14
Total	22.00	21.32	21.8
Outside Italy
Retail	2.19	2.12	2.11
Wholesale	2.47	2.96	2.71
	4.66	5.08	4.82
Other sales	1.35	1.39	1.35
Total	6.01	6.47	6.17
TOTAL SALES	28.01	27.79	27.97

In 2023, retail sales of refined products (28.01 mmtonnes) were higher by 0.22 mmtonnes or by 0.8% than 2022 as result of higher volumes marketed abroad partly balanced by lower sales in Italy.

Retail sales in Italy

In 2023, retail sales in Italy were 5.32mmtonnes, substantially in line with the 2022.

Average gasoline and gasoil throughputs (1,479 kliters) were up by 34 kliters vs. 2022 (1,445 kliters). Eni's retail market share of 2022 was 21,4%, lower than 2022 (21.7%).

As of December 31, 2023, Enilive's retail network in Italy consisted of 3,976 service stations, lower by 27 units from December 31, 2022 (4,003 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (23 units), the negative balance of the Company-owned stations (1 units), of the lower motorway concessions (3units).

Retail sales in the Rest of Europe

Retail sales in the Rest of Europe were 2.19 mmtonnes, an increase by 3.3% from 2022 as a result of higher volumes sold mainly in Germany and Switzerland, partly balanced by the decrease of the volumes in France.

At December 31, 2023, Eni's retail network in the Rest of Europe consisted of 1,291 units, increasing by 51 unit from December 31, 2022, mainly thanks to the openings in Germany, Spain and France, balanced by the reductions in Austria and Switzerland. Average throughput (2,166 kliters) increased by 138 kliters compared to 2022 (2,027 kliters).

Other businesses

Wholesale

Enilive is strongly present in wholesale market in Italy, including sales of diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels as well as sales of fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Enilive provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Customer care and product distribution are supported by a widespread commercial and logistical organization presence throughout Italy and is articulated in local marketing offices and a network of agents and concessionaires.

In 2023, sales volumes on wholesale markets in Italy (6.45 mmtonnes) increased by 4.2% from 2022, mainly due to higher sales of jet fuel which offset the reduction registered in the other segments.

Wholesale sales in the Rest of Europe were 1.94 mmtonnes, down by 20.5% from 2022 mainly in Germany, Spain and Austria.

Supplies of feedstock to the petrochemical industry (0.44 mmtonnes) increased by 12.8%. Other sales in Italy and outside Italy (11.14 mmtonnes) increased by 0.39 mmtonnes or up by 3.6%, mainly due to higher volumes sold to other oil companies.

LPG

The marketing of LPG in Italy is supported by the refining production and a logistic network made up of two bottling plants, one owned storage site and coastal storage sites located in Livorno, Naples and Ravenna.

LPG is used as heating and automotive fuel. In 2023, Eni share of LPG market in Italy was 15%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 36.5%.

Lubricants

Eni operates five (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, Africa and in the Far East. With a wide range of products composed of over 650 different blends Eni masters internationalstate of the art know how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, grease, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases, manufactured at Eni's refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero.

In 2023, Eni's share of lubricants market in Italy was 15.3%, in Europe below 2% and on a worldwide base below 1%. Eni operates in more than 80 countries by subsidiaries, licensees and distributors.

Oxygenates

Eni's, through its subsidiary Ecofuel (100% Eni's share), sells approximately 0.98 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 79% of oxygenates are produced in Eni's plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 21% is purchased.

Chemicals

Competitive trends in the industries where the Company operates

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), which 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 endmarkets. 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 2023, the Eni's chemicals business recorded significant operating losses due to the above-mentioned trends that have been compounded by a slowdown in demands for basic commodities. Management believes the profitability prospects of the chemicals business to remain weak in the foreseeable future and therefore the carrying amounts of the Company's chemicals plants were marked down to account for lower recoverable values with an impairment loss of about €0.4 billion.

Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production hubs are located in Italy and Western Europe. Eni is also engaged in the development of chemicals from renewable sources and recycled materials.

The business results of operations in 2023 and its strategy are described in "Item 5 – Group results of operations" and "Item 5 – Management's expectations of operations".

In 2023, sales of chemical products amounted to 3,117 ktonnes and decreased significantly from 2022 (down by 635 ktonnes, or 16.9%). In particular, the main reductions were recorded in olefins (down by 26.3%), derivatives (down by 19.4%), aromatics (down by 17.9%) and styrenic (down by 12.0%). In the moulding & compounding business, sales amounted to 67 ktons, down by 11.8% from the comparative period. Those reductions where due to a downturn in global demand for petrochemical commodities and rising competitive pressures.

Average sale prices of the intermediates business decreased by 17.4% from 2022, with olefins and aromatics down by 19.2% and 15.4%, respectively. The polymers reported a decrease of 25.9% from 2022.

Chemical production of 5,663 ktonnes decreased from 2022 (down by 1,193 ktonnes vs. 2022) due to lower production of intermediates business (down by 1,020 ktonnes), in particular aromatics and derivatives. The main reductions were registered at Mantua site (down by 220 ktonnes), Dunkerque (down by 185 ktonnes) and Priolo (down by 162 ktonnes). Those reductions where in response to lower sales volumes.

Plants nominal capacity decreased from the 2022. The average plant utilization rate, calculated on nominal capacity, was 51.4% (59.0% in 2022).

The table below sets forth Eni's main chemical products availability for the periods indicated.

		Year ended December 31,
	2023	2022
		(ktonnes)
Intermediates	3,877	4,897	6,284
Polymers	1,658	1,873	2,184
Biochem	57	5	8
Moulding & Compounding	71	81	20
Total production	5,663	6,856	8,496
Consumption losses	(3,247)	(3,923)	(4,590)
Purchases and change in inventories	701	819	565
Chemical products availability	3,117	3,752	4,471

The table below sets forth Eni's main petrochemical products revenues for the periods indicated.

	Year ended December 31,
	2023	2022	2021
		(€ million)
Intermediates	1,497	2,368	2,166
Polymers	2,152	3,203	3,114
Biochem	83	25	60
Moulding & compounding	276	327	70
Oilfield chemicals	97	83	65
Other revenues	131	209	115
Total revenues	4,236	6,215	5,590

Intermediates

Intermediates revenues (€1,497 million) decreased by €871 million from 2022 (down by 36.8%), following also the decrease reported in sales volumes (1,651 ktonnes, down by 23.5% vs. 2022). The main reductions were registered in olefins (down by 26.3%) and in aromatics (down by 17.9%). Average prices decreased by 17.4%, in particular olefins (down by 19.2%), aromatics (down by 15.4%) and derivatives (down by 14.1%). Intermediates production (3,877 ktonnes) registered a decrease of 20.8% from 2022. Decreases were also registered in olefins (down by 20.1%), in the aromatics (down by 23.0%) and in derivatives (down by 21.6%).

Polymers

Polymers revenues (€2,152 million) decreased by €1,051 million or 32.8% from 2022 due to lower sales volumes (down by 144 ktonnes) and the decrease of the average unit prices (down 25.9%).

The sold volumes of polyethylene business reported a decrease (down by 6.7%) due to lower sales of EVA (down by 18.1%), LDPE (down by 10.6%), and HDPE (down by 1.3%), in particular in the elastomers (down by 13.9%) and styrenics (down by 12%). In addition, average sale prices decreased by 30.5%.

In the elastomers business, were registered lower sales of BR (down by 23.4%), NBR rubbers (down by 16.8%) and SBR (down by 6.1%). Average unit prices decreased by 18.9%.

The decrease in sales volumes of styrenic was due to lower demand, which negatively affected GPPS sales (down by 15.7%) and HIPS sales (down by 15.1%).

Polymers productions (1,658 ktonnes) decreased by 11.5% from the 2022 due to the lower productions of polyethylene (down by 4.6%), elastomers (down by 16.2%) and styrenics (down by 16.0%).

Oilfield chemicals, Biochem e Moulding & Compounding

Oilfiled chemicals revenues increased by 16.9% (up by €14 million compared to 2022) as a result of the increased unit price (up by 14.6%).

Biochem business revenues (€83 million) increased by €58 million from 2022, mainly thanks to the inclusion of Novamont Group in the consolidation area starting from October 1, 2023.

Moulding & Compounding business revenues decreased by €51 million from 2022 (down by 15.6%) due to lower sales volumes (down by 12.3%).

Capital expenditures

See "Item 5 – Liquidity and capital resources – Capital expenditures by segment".

Plenitude & Power

Competitive trends in the industries where the Company operates

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 the 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.

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.

Plenitude & Power engages in the activities of retail sales of gas, electricity and related services, in the production and wholesale sales of electricity from thermoelectric and renewable plants, as well as in e-mobility services. It also includes trading activities of CO² emission certificates and forward sale of electricity with a view to hedging/optimising the margins of the electricity.

The business results of operations in 2023 and its strategy are described in "Item 5 – Group results of operations" and "Item 5 – Management's expectations of operations."

Plenitude

Overall Eni supplies 10.1 million retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 8.2 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.

Retail and business gas and power sales

Gas sales by market		2023	2022	2021
ITALY	(bcm)	4.11	4.65	5.14
Retail		2.91	3.34	3.88
Business		1.20	1.31	1.26
INTERNATIONAL SALES		1.95	2.19	2.71
European markets:
France		1.54	1.69	2.17
Greece		0.26	0.33	0.39
Other		0.15	0.17	0.15
RETAIL AND BUSINESS GAS SALES		6.06	6.84	7.85

In 2023, retail and business gas sales, in Italy and in European markets, amounted to 6.06 BCM, down by 0.78 BCM or 11.4% from 2022. Sales in Italy amounted to 4.11 BCM, a decrease of 11.6% (down by 0.54 BCM) compared to 2022, as a result of lower sales to the residential segment.

Sales in the European market were 1.95 BCM, decreasing by 11% (down by 0.24 BCM) compared to 2022. Lower volumes were marketed in France and Greece.

In Europe, Plenitude operates through the subsidiaries Eni Gas&Power France SA (99.999% 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 2023, retail and business power sales to end customers, managed by Plenitude and its subsidiaries companies in France, Greece and Iberian Peninsula, amounted to 17.98 TWh, a decrease by 4.2% from the full year 2022, due to the negative impact of climatic conditions and lower consumption abroad, partly offset by the increase in sales in Italy.

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 partnership.

		2023	2022	2021
Energy production sold from renewable sources	(TWh)	3.98	2.55	0.99
of which: photovoltaic (a)		1.74	1.13	0.40
wind		2.24	1.42	0.59
of which: Italy		1.53	0.82	0.40
outside Italy		2.45	1.73	0.59

(a) It includes biogas generation.

Energy production from renewable sources amounted to 3.98 TWh in 2023 (of which 1.74 TWh photovoltaic and 2.24 TWh wind) up by 1.43 TWh, or 56% compared to 2022.

The increase in production compared to the previous year benefitted from the entry in exercise of new capacity, mainly for the contribution of acquisition of assets in operation in Italy, Spain and the United States as well as for the organic developments of projects in Italy, United States and Kazakhstan.

TOTAL INSTALLED CAPACITY FROM RENEWABLES AT PERIOD END

(ENI'S SHARE)	(gigawatt)	2023	2022		2021
		3.0	2.2		1.1
of which: - photovoltaic (including installed storage capacity)		64%	54%		49%
- wind		36%	46%		51%
		(gigawatt)	2023	2022	2021
Italy			1.0	0.8	0.5
Outside Italy			2.0	1.4	0.7
United States			1.3	0.8	0.3
Spain			0.4	0.3	0.1
Other (Australia, France, Kazakhstan, UK)			0.3	0.3	0.3
TOTAL INSTALLED CAPACITY (INCLUDING INSTALLED STORAGE CAPACITY) *			3.0	2.2	1.1

* Installed storage capacity amounted to 21 MW, 7 MW and 7 MW in the 2023, 2022 and 2021, respectively.

At the end of 2023, the total installed capacity for the generation of energy from renewable sources amounted to 3 GW (in Eni share and including the storage power), up by 0.8 GW vs 2022 mainly due to the acquisitions in Spain (Bonete) and in the United States (Kellam plants as well as the acquisition of further 3 photovoltaic plants with a total capacity of approximately 0.4 GW, defined at the end of 2023) and the organic development of projects in Italy, Spain and Kazakhstan.

E-mobility

In a context of the mobility market that includes 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, 2023, there are 18,990 charging points distributed throughout Europe, in particular in Italy.

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 2023, power sales in the open market were 19.88 TWh, representing a decrease of 11.1% compared to 2022 due to lower volumes marketed to power exchange.

Power availability	2023	2022	2021
		(TWh)
Power generation sold	20.66	21.37	22.31
Trading of electricity (a)	6.64	9.49	11.62
	27.30	30.86	33.93
Power sales in the open market	19.88	22.37	28.54
Power sales to Plenitude	7.42	8.49	5.39

(a) Include positive and negative imbalances (differences between power introduced in the grid and the one planned).

Power generation

Enipower's power generation sites are located in Brindisi, Ferrera Erbognone, Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2023, installed operational capacity of Enipower's power plants was 2.2 GW. In 2023, thermoelectric power generation was 20.66 TWh, down by 0.71 TWh compared to 2022. Electricity trading (6.64 TWh) reported a decrease of 30% from 2022, due to the optimization of inflows and outflows of power.

Site	Total installed capacity in 2023 (Eni's share) (a) (MW)	Technology	Fuel
Brindisi	647	CCGT	gas
Ferrera Erbognone	536	CCGT	gas/syngas
Mantova	375	CCGT	gas
Ravenna	433	CCGT/Peaker	gas
Ferrara	204	CCGT	gas
		Power
Bolgiano	33	station	gas
Photovoltaic plants (b)	0.1	Photovoltaic	Photovoltaic
	2,228

(a) Installed operational capacity

(b) Managed by EniPower Mantova

Power generation		2023	2022	2021
Purchases
Natural gas	(mmCM)	4,144	4,218	4,670
Other fuels	(ktoe)	156	175	93
- of which steam cracking		85	86	68
Production
Electricity	(TWh)	20.66	21.37	22.31
Steam	(ktonnes)	6,981	6,900	7,362
Installed generation capacity (*)	(GW)	2.2	2.3	4.5

(*) Eni's share.

Capital expenditures

See "Item 5 – Liquidity and capital resources – Capital expenditures by segment".

Corporate and Other activities

These activities include the following businesses:

• the "Other activities" segment comprises results of operations of Eni's subsidiary Eni Rewind (former Syndial SpA) which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and
• the "Corporate and financial companies" segment comprises results of operations of Eni's headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni's headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. From the fourth quarter of 2023, the results of CCUS and Agribusiness, under development, have been included in the "Corporate and other activities" reporting segment, previously they were reported as part of the Exploration & Production segment results. Comparative reporting periods have been restated accordingly; however the overall impact was immaterial. Through Eni's subsidiaries Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance DAC, Eni carries out cash management activities, administrative services to its foreign subsidiaries, lending, factoring, leasing, financing Eni's projects around the world and insurance activities, principally on an intercompany basis. Eni Servizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni's activities in these areas to be material to its overall operations.

Seasonality

Eni's results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months and lowest in the third quarter, which includes the warmest months. Moreover, year- to-year comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residentialspace heating. In colder years, which are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa.

Research and development

Eni's Research and Technological Innovation is a key element to make effective and efficient access to new energy resources, improve the use of existing ones and at the same time reduce the impact on the environment. The objectives are, therefore, declined on the following strategic directives:

• process decarbonization: with the aim of reducing, capturing, transforming or storing CO2, increasing energy efficiency, reducing emissions and promoting energy vectors with a low carbon footprint;
• circular and bio-products: with the aim of reducing, recycling and reusing products and by-products, transforming waste into value-added products for biorefinery, sustainable mobility and biochemicals;
• renewables and new energies: with the aim of supporting the development of renewable energies and energy storage solutions, and to develop breakthrough energy technologies such as magnetic confinement fusion;
• operational excellence: with the aim of developing technologies that ensure the highest level of efficiency and safety, the lowest environmental impact, while reducing costs and time to market of our activities.

A key point of Eni's research and innovation is the integrated and transversal approach being a lever to create value, with the aim of minimizing the time to market that from research leads to the development of technologies and their implementation on an industrial scale.

In 2023, Eni filed 28 patent applications (23 in 2022).

In 2023, Eni's overall expenditure in R&D amounted to €166 million which were almost entirely expensed as incurred (€164 million in 2022). In 2023, about 80% of total R&D expenditures were dedicated to the decarbonization, renewable energies and circular economy.

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.

Talking about technological path under development, in the decarbonization path Carbon Capture Utilization and Storage (CCUS) represents an important lever, where technologies, skills and innovation are and will be key to success. Innovative solutions are studied in terms of capture technologies as well as new power generation systems with integrated capture. Hub solutions, transport networks and offshore injection network in depleted fields are also studied, taking advantage of the expertise acquired on gas developments, through an incremental innovation approach.

Great expectations at the decarbonization level come from Carbon Utilization initiatives, where our research efforts are significant. In particular, CO² reduction to methane or methanol (e-fuels) and mineralization technologies are being developed. Mineralization of CO² with minerals that are widely available in nature allows significant amounts of gas to be permanently fixed in inert, stable and non-toxic phases. The distinctive and innovative feature of our technology lies in the fact that we have been able to develop properties that allow the product to be used in the formulation of cements, thus opening the way to a potentially huge market.

Of equal importance is the approach typical of the circular economy, i.e. with a focus on research and development that looks at the entire lifecycle of technologies, with the aim of developing new and creative solutions along the entire value chain, making it possible to achieve significant savings in resources and energy, with considerable benefits for the environment.

To be effective, however, it needs to be implemented through integrated multidisciplinary approaches and with the involvement of all the actors in the value chain: companies, institutions, civil society.

Finally, scientific research and digitization will make it possible to do even more: smart digital solutions to be applied in all areas can, on their own, contribute substantially to reducing CO² emissions by 2030. In fact, the ongoing digitalization process has the potential to accelerate the energy transition process, generating important benefits in terms of efficiency and environmental impact. Numerous projects have been launched at Eni: for example, for each physical asset a "digital twin" will be created through which it will be possible to predict and control operations in advance; with the widespread application of sensors and the use of advanced algorithms, Eni expects to be able to improve the performance and reduce the emissions of its activities.

Insurance

In order to control the insurance costs incurred by each of Eni's business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance DAC, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group's results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market. Eni enters into insurance arrangements through its shareholding in the Everen Ltd (a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment 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 environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to \$1.1 billion for offshore events and \$1.3 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: \$1.3 million for tankers and charters and up to \$1 billion for FPSOs used by the Exploration & Production segment for developing offshore fields.

Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one that occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See "Item 3 — Risk factors — Risk associated with the exploration and production of oil and natural gas".

Environmental matters

Environmental regulation

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in the 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 in order to comply with pending environmental, health and safety protection and safeguard regulations, particularly in order to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere and cope with climate change and water quality of discharges, as well as 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.

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 as 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 last UN Climate Change Conference of Parties (COP 28), taken place in Dubai, 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 the hydrocarbons demand could structural decrease in the medium to long term time, 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 a new business opportunity 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 will 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.

In the energy efficiency field, the new directive introduces a series of measures and embraces the "energy efficiency first" principle. The main features and changes from the previous directive includes:

• increasing annual energy savings from 0.8% (at present) 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 an 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.

In 2022, the efforts of the European Commission legislators focused on several proposals to support enhanced nonfinancial disclosure obligations for financial market participants, financial advisors and large corporations.

On 23 February 2022, the European Commission published its proposal for a Directive on Corporate Sustainability Due Diligence. The future Directive and its national transposition rules should apply to large (more than 250 employees) and very large companies (more than 500 employees) and require the creation of a system to monitor, prevent and mitigate the negative impacts on the environment, working conditions and individual rights and freedoms of both the company's activity and the upstream and downstream value chain (suppliers, distributors, retailers, etc.).

A provisional agreement between the EU institutions was reached at the end of December 2023 which needs to be formally approved and adopted by both institutions.

The Corporate Sustainability Reporting Directive (CSRD) is another key initiative of the Green Deal for Europe and is part of a broader regulatory framework with 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. The CSRD amends Directive 2013/34/EU on non-financial business information by introducing ad hoc provisions on corporate sustainability reporting.

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 European Commission has proposed stronger rules on ambient air quality, setting an 'interim' 2030 EU air quality standards, aligned more closely with 2021 World Health Organization guidelines, while putting the EU on a trajectory to achieve zero pollution for air at the latest by 2050, in synergy with climate-neutrality efforts. In particular, the key proposed change is a tighter annual limit value for fine particulate matter (PM2.5) of 10 µg/m3, effective from 2030, down from the current limit of 25 µg/m3. In November 2023, the Council adopted its negotiating mandate for talks with the European Parliament to shape the final text of the legislation.

The Industrial Emission Directive (IED) 2010/75/EU is fundamental for European industries, it provides the framework for granting permits for about 50,000 industrial installations across the EU. It 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. As foreseen in the European Green Deal roadmap, the European Commission got int the heart of the review of the IED (Industrial Emission Directive) . On 5 April 2022, the EU Commission presented a proposal for a directive revising, updating, and modernising Directive 2010/75/EU. The text published in the EU Official Journal proposes a revision of the measures to tackle pollution from large industrial installations in order to offer better environmental and human health protection. At the same pace the European Commission is revising the European Pollutant Release and Transfer Register (E- PRTR) Regulation to improve environmental data reporting. In November 2023, the Council and the European Parliament successfully concluded negotiatons with a provisional political agreement. The deal is pending formal adoption by both istitutions.

In particular, the main areas of improvement include: expansion of sectoral coverage and new pollutants of concern, better coherence with related environmental legislation and collecting information that helps contribute to the circular economy and decarbonisation and enhancing the quality, ease and speed of public access to information.

On 12 May 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. The 25th October 2022, the European Commission published the proposal for the new Urban Wastewater Treatment Directive (UWWTD). The proposal focuses on the quality of rivers, lakes, groundwaters and seas through cost-effective wastewater treatment. It includes essential points, such as the energy-water nexus, nutrients recovery and new requirements for microplastics and other micropollutants in line with the Circular Economy Action Plan. The sector is supposed to become energy-neutral by 2040. Moreover, the proposal also aims for new standards and limit values, an extended producer responsibility, better and digitalized monitoring and tracking of pollution, and a cooperation between health and wastewater competent authorities.

The European Commission decided to revise the Waste Framework Directive, in order to reduce waste generation, improve waste collection and optimize recycling, increase the collected amount of waste oil and ensure its treatment according to the EU waste hierarchy; a call for ideas took place between 25th January 2022 and 22nd February 2022 and a legislative proposal was presented on 5th July 2023, including measures aimed to tackle food and textile waste.

In January 2023 the European Parliament approved a text for the revision of the Regulation 1013/2006 regarding the international waste shipments. The Swedish presidency, which started on 1 January, aims to reach a general approach on the file at the Environment Council on 20 June 2023. The proposal of European Commission, which was presented on 17 November 2021, aimed to set 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.

The Council adopted its general approach on 24 May 2023. Interinstitutional negotiations concluded on 17 November 2023 with a provisional agreement. The agreed text, endorsed by Member State representatives on 6 December 2023 and by the ENVI committee on 11 January 2024, now awaits formal adoption by Parliament and the Council. The vote of the EP is expected by 1Q2024. According to the agreement, export of plastic waste from the EU to non-OECD countries will be prohibited; only if strict environmental conditions are met, individual countries may receive such waste five years after the entry into force of the new rules. 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. At the same time, it will be easier to ship waste for recycling within the EU thanks to digitalised procedures. The new regulation should also support the development of waste market to boost circular economy and increase the security of supply of raw materials, and tackling waste trafficking, by a stronger cooperation between EU Member States and more deterrent sanctions, and with the direct involvement of the EU Anti-Fraud Office in the investigations by Member States these issues.

In March 2020 the European Commission adopted a new Circular Economy Action Plan (CEAP), one of the main building blocks of the European Green Deal. With measures along the entire life cycle of products, the new Action Plan aims to make our economy fit for a green future, strengthen our competitiveness while protecting the environment and give new rights to consumers.

As part of the European Green Deal and the new circular economy action plan, the European Commission put forward a revision of the PPWD in November 2022. The initiative's objective is to ensure that all packaging is reusable or recyclable in an economically feasible way by 2030. The aim is to reinforce the essential requirements for packaging to ensure its reuse and recycling, boost the uptake of recycled content, and improve the requirements' enforceability. Measures are also envisaged to tackle over-packaging and reduce packaging waste. On 18th December 2023 the European Council adopted its negotiating position, aiming at a balance between keeping the proposal's ambition to reduce and prevent the generation of packaging waste, and allowing member states sufficient flexibility.

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 Emission 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 2023 to comply with this carbon emissions scheme, Eni purchased on the open market allowances corresponding to 11.5 million tons of CO2 emissions incurring expenses of around €950 million (16.73 million tons in 2022 for a total expense of €950 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 significantly higher operating expenses in case the Company is unable to reduce the carbon footprint of its operations.

<-- PDF CHUNK SEPARATOR -->

European Union Health and Safety Laws Framework

Legislative Decree No. 81/2008 concerned the protection of health and safety in the workplace and was designed to regulate the work environments, equipment and individual protection devices, physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals.

With Law 215 of 17 December 2021, important innovations were introduced into Legislative Decree 81/08. These changes bring a much-needed initial novelty and update to a number of prevention and control issues in the workplace, such as:

• Regional coordination committees;
• Joint organisms;
• Role of the "Preposto";
• National prevention information system;
• Vigilance;
• Suspension of activities;
• Training.

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 with the aim of obtaining opinions on the expected impacts of the envisaged changes.

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 which materialize with the publication of adjustments and delegated regulations on specific topics; those that have had the greatest impact on Eni and the companies that produce and market products in recent years are:

• Regulation (EU) 2020/878 published on 26 June 2020, amending Annex II of REACH relating to the "Requirements for completing safety data sheets (SDS)" for substances and mixtures, in force since 16 July 2020, applicable from 1 January 2021.

This represents a challenging moment for the company that manages a large number of SDSs, as starting from 1 January 2023 all SDSs will necessarily have to be drawn up in accordance with this Regulation.

• Regulation (EU) 2017/542 of 22 March 2017 which amends Regulation (EC) no. 1272/2008 (CLP) of the European Parliament and of the Council on classification, labeling and packaging of substances and mixtures of the European Parliament and of the Council on classification, labeling and packaging of substances and mixtures through the addition of an annex on harmonized information on emergency health response and its subsequent amendments. In fact, starting from January 2021, in Italy, new dangerous preparations for consumer and professional use must be notified on the ECHA portal through the PCN (Poison Centers Notification). While previously, information on the dangerous mixture had to be sent to the ISS by 30 days from the date of placing on the market, now the submission of information has to be done to ECHA before the mixture is placed on the market.

• Delegated Regulation 2023/707 amending CLP Regulation, in force fron 20 April 2023, which sets out new hazard classes and criteria for the classification, labelling and packaging of substances and mixtures.

• Update of Annex VII of REACH Regulation (5 update in 2023)

• Evolution on PFAS (Per- and polyfluoroalkyl substances) regulation and restrictions that involved about 10000 substances. ECHA's scientific committees will now start evaluating the proposal in terms of the risks to people and the environment, and the impacts on society.

It applies to all chemical substances and mixtures placed on the EU market under REACH. It also applies to active substances in biocidal products and plant protection products, which are normally prioritised for harmonised classification in the EU.

Compliance with REACH requirements and the involvement of all stakeholders in the Company are coordinated and supervised by the HSEQ/Product Safety function.

Since 2022 Eni has been actively involved in the public consultation of the REACH Regulation and the CLP Regulation and recently Ecodesign for Sustainable Products (ESPR) Regulation for an analysis of the resulting impacts.

Legislative Decree 101/20 has adopted Directive No. 2013/59/EU establishing safety standards in order to protect people from the risks deriving from ionizing radiation. The Decree regulates the protection of people subject to exposure to ionizing radiation from artificial and natural radioactive sources.

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.

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 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 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.

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. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will probably increase in future years.

Moreover, in order to achieve the highest safety standards of our operations in the Gulf of Mexico, Eni entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Well Containment Group (HWCG) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.

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 industryfunded 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 2023

Eni is committed to continuously improving its model for managing health, safety and environment 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 2023, 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 333, of which:

• 98 certifications according to the ISO 14001 standard;
• 10 registrations according to the EMAS regulation;
• 26 certifications according to the ISO 50001 standard (certification for an energy management system);
• 106 according to the new ISO 45001 standard;
• 41 according to the ISO 9001 standard (certification of the quality management system).

In 2023 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 84% for the ISO 45001 standard and 83% for the ISO 14001 standard.

In 2023, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,419 million (-7% vs 2022).

Environment.

In 2023, Eni incurred total expenditures of €1,065 million for the protection of the environment (with a decrease of 7% with respect to 2022). Environmental expenditures are mainly related to remediation and reclamation activities (€519 million), waste management (€223 million), water management (€153 million), air protection (€64 million) and spill prevention (€44 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 2023, the new legislation did not have a significant impact on the procedures already in place for occupational and process safety. In 2023, the commitment to reduce accidents continues at Eni, which has also focused on new projects:

• 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 the new training course dedicated to Operational Safety Management, reserved for operational and HSEQ area personnel, with the aim of familiarising them with the basic principles and minimum safety requirements to be applied in risky activities;

• deployment of the new training course on Process Safety Management, addressed to HSE as well to operating personnel, in order to provide them with basic information relevant to Process Safety and its Management System;

• training of expert personnel on the new RC Eni investigation methodology, which enables the identification of root causes and effective action to prevent the recurrence of accidents;

• extension to all operational sites of the digital Safety Presense tool, which, with the help of artificial intelligence and machine learning, enables predictive analysis by exploiting the data available in the safety reporting, sending the site an alert when it detects a high frequency of recurring hazardous situations that retrace a past accident.

• the Campaign of diffusion of Process Safety Fundamentals has continued and gained additional maturity in all Eni subsidiaries. Process Safety Fundamentals are key operating principles that, if respected, may contribute to the reduction of approximately one third of Company Process Safety Events.

In terms of industrial hygiene, great attention was paid to the identification and management of personal protective equipment (PPE). In 2023 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.

In addition, during year 2023, Eni has also focused on development of a new training course dedicated to operational industrial hygiene management, reserved for operational and HSEQ area personnel, with the aim of increase and share knowledge, principles and requirements to be applied in sampling and monitoring of risk agents.

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, has validated a methodology for the mapping of TENORM matrices in Eni sites all over the word and has implemented management systems for monitoring the disposal of matrices contaminated by natural radionuclides

In 2023, the total recordable injury rate (TRIR) of the workforce decreased compared to 2022 (0.40 versus 0,41 in 2022), despite the number of total recordable injuries increased (122 versus 113 in 2022). There was 1 fatality to contractors in upstream operations in Nigeria.

In the area of emergencies, particular attention was paid to the prevention and management of emergencies induced by natural risks and in November 2021 a Memorandum of Understanding was signed between Eni and the Department of Civil Protection, to further 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 6,000 exercises.

Costs incurred in 2023 to support the safety levels of operations and to comply with applicable rules and regulations were €288 million.

Health activity for 2023.

Eni protects and promotes the health, considering its physical, mental and social dimensions, of its people, workers, families and communities, through a management system based on the principles of precaution, prevention and promotion.

The total amount spent in 2023 was €57.9 million divided into: occupational health and industrial hygiene activities, medical assistance and health emergencies, health promotion, Global Health activities in favor of communities.

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 expectations of stakeholders and the potential impacts on health deriving from company's activities, with continuous monitoring of any presence of epidemic and pandemic outbreaks. In order to guarantee people's health at every stage of the business cycle, a dedicated 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.

In 2023, a customer satisfaction survey was conducted on the entire Eni population in Italy to evaluate the perception of Eni's people on the health services provided. From the analysis, Eni is perceived as a community active in promotion and prevention and generally committed to spreading a culture of health.

Main 2023 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 in biorefineries, biogas production and agribusiness processes.
  • Testing of new Internet of Things technologies: 49 sensors were tested at on-shore operating sites in Italy for monitoring the healthiness of indoor working environments to protect the health of workers.
• 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 70% of employees, expected to extend to 85% by 2027.
  • Psychological First Aid Service (PFA) available to all employees in Italy and abroad in cases of catastrophic and unexpected events.
  • Specific services regarding gender health and assistance have been activated, such as in Italy a helpline dedicated to victims of gender harassment and violence.
  • "Più Salute" has been extended throughout Italy, a package of free health care services for Eni people and their families which provides extended care 24 hours a day, to respond to needs, from telemedicine to home medical services, from booking at health facilities to the anamnestic interview.
• Health promotion:
  • Raising awareness in relation to endemic diseases, such as tuberculosis and malaria, sexually transmitted diseases, non-communicable diseases, such as diabetes and hypertension.
  • Extension of the "Previeni con Eni" service to many Italian cities, a free biennial checkup for cancer and cardiovascular prevention.
  • Provision of the influenza vaccination campaign in Italy.
• Global health:
  • 11 Health Impact Assessment (HIA) studies completed, of which 6 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 15 countries, reaching over 330,000 beneficiaries
  • Collaboration with health institutions and organizations in the countries of presence was strengthened by signing of 12 agreements.

In 2023 Eni activated a virtuous public-private partnership with the ILO aimed at improving safety and health at work and access to social health protection measures. The beneficiaries will be 150,000 small farmers in the agro-industrial sector in Kenya and Ivory Coast, where Eni is developing projects for the production of vegetable oil, not in competition with the food chain, to supply biorefineries.

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.

The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, higher-than-average rates of income taxes, additional royalties and taxes on production, environmental protection measures, control over the development and decommissioning of fields and installations, and restrictions on production. A description of the main regulations which impose restrictions and liabilities to the Company's businesses is provided below.

Overview

The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments.

Regulation of exploration and production activities

Eni's exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements.

Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any production taxes or royalties, whichmay be in cash or in-kind. Concession contracts currently appliedmainly 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 (exceptfor 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, pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with localtax 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 relevantmineralright.

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.

Regulation of the Italian hydrocarbons industry

The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments.

Exploration & Production

The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the "Hydrocarbons Laws").

Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession granted by the Ministero dell'Ambiente e della Sicurezza Energetica - MASE or, in some specific cases (e.g. special-status region) by the Region.

The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State (only for initial acreages larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the end of the field economic life.

These provisions are to be coordinated with a new law effective as of February 12th, 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 28th, 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 13th, 2024, TAR Lazio ruling declared void PiTESAI. As a consequence, MASE could adopt a new plan to identify suitable areas hydrocarbon exploration, development and production activities or could file an appeal before the Council of State in order to restore the validity of PiTESAI.

That said, pending the final judgement and for the sake of completeness we provide below a brief description of PiTESAI's main provision.

Exploration permits maintain their efficacy in areas identified as "suitable" and limited to gas exploration target ; on the contrary, in "unsuitable" areas, exploration permits are withdrawn.

As far as development and production concessions are concerned, they can be maintained or extended if their infrastructures are located in suitable areas with production ongoing or suspended by less than 7 years; ; on the contrary, for development and production concessions whose infrastructures are located in unsuitable areas, further extensions can be granted only if:

• they are productive or have been unproductive for less than 5 years (offshore case);
• they are productive or have been unproductive for less than 5 years and they have successfully passed a cost-benefit analysis (onshore case);
• ongoing concessions applications can be filed for gas exploitation only having associated reserves greater than 150Msmc.

Starting from June 1st, 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.

On March 1st, 2022, the Italian government issued a first Decree (D.L. Energia) aimed at boosting the national production by mitigating the effects of PiTESAI. This was converted into law on April 27th, 2022.

A second decree, with the same objectives was issued on December 9th, 2023, providing the ground for new upstream development opportunities converted into law on 2nd February, 2024.

Regardless of the validity and the effects of PiTESAI, it is important to highlight that such plan did not entail any significant and adverse consequence on Eni's development and producing activities at its Italian concessions or on assets useful lives even due to provisions of the two recent above mentioned

Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 – Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with exemptions only for on shore gas concessions with production lower than 10 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20.06%, with no exemptions).

Gas & Power

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

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 retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users who are opting for adhering to regulated tariffs until the market is fully opened. 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 cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results, and cash flow

Wholesale gas market in Italy

In the last decade, and even more in the last years, a number of new rules have been introduced in order to 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 allocation criteria based on 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 storage operators and LNG terminal operators by means of specific parallel measures. Thanks to these reforms, much higher levels of capacity bookings have become structural for both types of infrastructures, and more LNG deliveries have been attracted in recent years to the country.

– An organized market platform (MGAS) for gas trading and gas balancing market, 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).

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 a number of 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) further incentivize storage booking and filling, ensuring the compliance with the new filling trajectories 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 prices in the retail sector in Italy

Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the 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, the 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 oilbased 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 will no longer have access to regulated tariffs for gas supplies. Consumers will have to choose among the different pricing proposals made by gas selling companies, while only vulnerable customers will be 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.

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 periodic 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 in Italy, France and Belgium have recently been redefined for the four-year period 2024-2027, but the re-definition of transportation tariffs criteria at pre-established 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 in the future could determine impacts on logistic costs. Further rule changes – representing risk factors as well as business opportunities - could concern the regasification and storage sector, also in consideration of the market context following the energy crisis in 2022-2023 and of need to pursue new solutions to ensure European security and diversification of supplies.

Moreover, the energy crisis scenario that materialized in 2022 has directed legislators, at European and individual country level, towards evolutions - albeit temporary - of the legislation and the consequent regulations that can impact the market dynamics, with the aim of containing prices for end customers and improve the security of supplies (e.g. possible obligations to reduce final consumption, caps on prices of derivatives on wholesale gas products traded on regulated markets, possible storage obligations, obligations of ex-ante notification to the European Commission concerning new supply contracts).

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 costumers 5% VAT, distribution companies continue to invoice retailers at the normal 21% rate. The Spanish government has announced that the value-added tax rate for energy bills will gradually return 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. For 2024, electricity regulated tariffs are no longer capped. Public mechanisms to support professional consumers were maintained only for contracts signed at a high price before the end of June 2023.

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).

In the medium term, we could expect that gas demand at European level will be supported by the need of accelerating the phase-out of coal-based power generation in view of the decarbonisation targets. On the other side, with the implementation of the EU Green Deal and of the subsequent and more ambitious decarbonisation interventions, in the coming years the regulation of the gas sector will presumably 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 which will accompany 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). These changes will likely cause pressure on the natural gas business, but on the other side they will likely open and support new business opportunities in the renewable and decarbonized gases business that Eni is ready to pursue.

With regard to power sector, Italian Capacity Market auctions, taken place in November 2019 and in February 2022, allocated capacity with delivery in 2022, 2023 and 2024 to the power producers. 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). There is a residual risk that the tenders could be canceled due to the administrative appeal filed by some power companies against the tender procedure.

At the end of 2023, with a consultation concerning some changes in the Italian Capacity Market Guidelines, Terna (the Italian TSO) started the process towards the Capacity Market's auctions with delivery 2025, 2026 and 2027 which it will complete by Terna with the publication of the final release of the Capacity Market Guidelines and by ARERA with the publication of the auction reserve price and of the other economic variables. The auctions will likely take place before 4Q 2024. The extension of Capacity Market, it will stabilize the revenue of power generation from gas until 2027. The Capacity Market for the allocation capacity with delivery 2028 will be carried on if a new adequacy assessment conducted by the TSO will confirm the presence of adequacy concerns. After 2028, Capacity Market Guidelines shall be completely rebuilt because the current mechanism has been approved by European Commission till December 31, 2028.

Besides, in the next years Italian power market design could significantly be affected by the implementation of European market model. The main innovations concern 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, fostering 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"), that shall enter into force from 1.1.2025. Management believes that all these issues will increase competition, in particular in the Italian balancing market which will be also affected by the incentive granted to Terna in order to minimize the balancing market cost.

The ongoing revision of the European electricity market design carried by the Commission, as a result of the crisis, could lead to profound changes which would be felt across EU markets. In a public consultation launched in January, the Commission proposes a large range of policy changes to protect consumers from high prices. On 14 March the Commission's proposal for a regulation would amend four pieces of legislation: 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 proposal is more targeted and limited in the changes that were initially anticipated, most notably it conserves the merit-order pricing system. However, as it currently stands, it would introduce several obligations on suppliers. First, an obligation to offer fixedprice, 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. This reform is likely to be adopted before the end of the year, and once the regulation enters into force, member states will have to prepare the necessary national measures within 6 months.

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 IIIQ2023) and the reinstatement of system charges for the electricity sector (starting from IIQ23), the 5% VAT reduction for gas, which was still in place until IVQ2023, 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 IQ24).

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 Nov. 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, represents an element of uncertainty 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.

Refining and marketing of petroleum products

Refining. The current regulations 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.

In 2022 refining operations benefitted from a number of interventions aimed at lowering utility costs, temporarily adopted by the legislator as part of the energy crisis response package. Some of these measures were confirmed in 2023 (es. reducing the parafiscal levies – Oneri di Sistema – charged on gas bills, tax credits until Q2 2023, reduction of VAT on gas consumptions⁸ ).

Marketing. Following the enactment of the Law Decree No. 1/2012, an increase level of competition in the retail marketing of fuels have been introduced. The rules regulating relations between oil companies and managers of service stations have been changed 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 of tax evasion in the sale of oil products that in the past produced anticompetitive effects on the sector. The law requires the advance payment of Value Added Tax (VAT) on oil products before the extraction from deposits or the sale to consumer.

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.

The new regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/UE 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. The legislation established, furthermore, an adequate number of charging stations accessible to the public to be created throughout the country by 2020.

⁸ L. 197/22, DL 34/23, DL 79/23, DL 131/23

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 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).

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).

In 2022, Law Decree No 17/2022 provided a new incentive framework for purchasing low-emission vehicles. The incentive framework has been confirmed for 2023.

Management believes that these measures will favor competition in the Italian retail market and enhance the competitiveness of efficient players.

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, were 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).

Law 238/2021 (European Law 2019-2020) confirmed the GHG saving requirement (6%) previously set for the year 2020 only and revised the calculation methodology for the current 7% maximum threshold for food-and-crop derived biofuels. The law excludes from the calculation fuels based on double counting feedstock.

The Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources has been transposed with the Legislative Decree No 199/2021. The Decree set new targets for RES penetration in the transport sector (16%) and introduced some innovations in the transport sector's regulatory framework: i) palm-oil, PFAD and EFB based fuels cannot contribute to RES targets in the transport sector. However, they can be taken into account if certified as low-ILUC risk ii) biomethane support schemes – as defined by the Ministerial Decree of March 2, 2018 – have been updated iii) Recycled Carbon Fuels count as renewable towards the general target, on the basis of the upcoming EU delegated acts and iv) confirms the use of some wastes as feedstock for the production of biofuels.

Law Decree No 17/2022 (converted into Law No 34/2022) further developed the regime set in Legislative Decree No 199/2021 (transposing Directive (EU) 2018/2001 - REDII), introducing an obligation for the fuels suppliers to supply pure bioliquids to be used in the transport sector (additional to the existing obligation on biofuels). The measure requires a mandatory cumulative share of at least 300 ktonnes released in 2023, with volumes increasing by 100 ktonnes per year and reaching 1 million tonnes per year from 2030 onwards.

The measure also incentivizes, by means of investment aid, existing refineries conversions aimed at producing the abovementioned pure biofuels. The incentive is financed by the Fund for the decarbonisation and green conversion of existing refineries, established under the Ministry of environment and energy security with an overall budget of € 260 million for the three- year period 2022-24, and will be regulated by a specific Ministerial Decree.

Provisions regarding both supply obligation and reconversion funding have been implemented by Decree No 107/2023 and No 343/2023 of the Minister of the Environment and Energy Security.

In particular, the methods and criteria for implementing supply obligations for the period 2023-2030 were regulated by Ministerial Decree No 107/2023 which also defines the trajectories for achieving all biofuels targets (traditional, advanced, pure biofuel and including the specific biomethane subtargets). The Decree No 107/2023 was then integrated by the Ministerial Decree No 343/2023. To comply with the national supply obligations, biofuels blended, with a minimum rate of 20%, are assimilated to the pure form only for a transitional period 2023-2024.

With 2021 budget law and other several 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.

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 R&M business area. It allocates €230 million to develop at least 40 recharging stations based on hydrogen for light and heavy vehicles by 2026. It also assigns €730 million for the installation of charging infrastructures for electric vehicles, envisaging the entry in operation, by 2025, of a minimum of 7.500 rapid recharging stations along freeways (at least 175 kW) as well as 13.000 rapid recharging stations in urban areas (at least 90 kW).

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.

Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 ("Decree 22/2001") enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister of Ecological Transition based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain.

As of December 31, 2023, Eni owned 4.6 mmtonnes of oil products inventories, of which 2.8 mmtonnes as "compulsory stocks", 1.5 mmtonnes related to operating inventories in refineries and deposits (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 (33%), light and medium distillates (33%), refinery feedstock (23%), fuel oil (9%), and other products (2%) were located throughout the Italian territory both in refineries (81%) and in storage sites (19%).

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 ("Article 101" and "Article 102", respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts do not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:

• requiring that an infringement be brought to an end;
• ordering interim measures;
• accepting commitments; and
• imposing fines, periodic penalty payments or any other penalty provided for in their national law.

National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the "EEA Agreement"), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni's activities are subject to Law No. 287 of October 10, 1990 (the "Italian Antitrust Law"). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements 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.

Property, plant and equipment

Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. The Company enters into operating lease contracts with third parties to hire plant and equipment such as floating production and storage offloading vessels (FPSO), drilling rigs, time charter, service stations and other equipment. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company' 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, 2023, there were 435 subsidiaries and 144 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, 2023 is provided in the "Item 18 - Notes to the Consolidated Financial Statements".

Item 4A. UNRESOLVED STAFF COMMENTS

None.

Item 5 5. OPER A TING AND FI N ANCIAL REVIEW AND P R OSPECTS

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.

Operating results

2023 trends in the crude oil and natural gas markets

In 2023, crude oil prices averaged 83 \$/bbl and declined by 18% compared to the average recorded in 2022, featuring another year of highly volatile crude oil markets with a considerable number of days when the Brent benchmark crude oil moved by more than 5 \$/bbl in a single trading day. After the spike in prices recorded in the previous year due to Russia's military aggression in Ukraine in February 2022, which triggered a short-term rally in the price of crude oil, with the Brent price approaching its all-time highs at approximately 140 \$/bbl in March 2022 and remaining elevated through the first half of 2022, the crude oil market entered a downturn that has run almost uninterrupted till the end of 2023.

In that timeframe, the oil price has corrected by about 40 \$/bbl or 33% compared to the price at the end of June 2022 at 125 \$/bbl to a 2023 average of about 83 \$/bbl. Many factors were behind that trend. First, Russia's production and export towards international markets have held remarkably well, defying expectations of market participants who had anticipated a likely supply shortfall. The imposition of sanctions from G-20 countries to limit Russia's primary source of revenues has proven ineffective at impairing Russia's ability to deliver barrels to countries like China and India.

In addition to Russia, supplies have continued to grow significantly elsewhere, with strong gains from various non-OPEC countries like Brazil, Guyana, China and above all in the United States, where productivity gains have made for reduced capital budgets at shale oil companies. The 2023 exit rate of US production at about 13 mmbbl/d has recovered the record level set before the onset of the COVID pandemic. Also sanctioned production at Iran and Venezuela has made its way to international markets, helped by a loosened enforcement of the embargo on Iranian oil, as well as a provisional lifting of Venezuela restrictions to export by US Administration. The OPEC+ alliance with an effort coordinated by Saudi Arabia has sought to limit supply by agreeing on a production cut of about 4 million barrels per day, effective till the end of 2024. OPEC+ agreed cuts were supported by Saudi Arabia unilateral, voluntary cut of one million barrels per day, effective from July and subject to review each month. However, the cartel delivered less cuts than announced, while Saudi Arabia has continued to roll over its unilateral cut till the end of 2023 and which is expected to continue in the first half of 2024.

The second trend behind the decline of crude oil prices was the positioning of hedge funds and commodity traders, who have gradually reduced their long exposure to the crude oil market by liquidating future contracts on Brent crude oil or the US WTI, driven by the tightening monetary policy adopted by the US Federal Reserveand other central banks to contrast a resurgence in inflation. Rising bond yields have reduced the appetite for more risky assets like commodities, also based on expectations of the negative impact of rising rates on economic activity and demands for commodities. The impact of tightening monetary conditions was compounded in the first half of 2023 by the failure of several regional banks in the US spreading fears of a financial crisis. In the last months of 2023, with inflation gauges in the US slowing down, hedge funds and commodity traders have again executed mass liquidation of Brent/WTI long future positions due to the inverted trade short oil/long bonds.

Finally, in response to the Russia's military aggression of Ukraine, the US Administration has implemented a program of releasing part of the SPR (Strategic Petroleum Reserve) by selling about one million barrels per day for a six-month period plus additional sales through the first half of 2023 for a total release of approximately 200 million barrels. Other OECD countries have executed similar sales to mitigate the war premium in crude oil prices.

Those development have all pressured crude oil prices downwards.

On the face of major uncertainties in global markets, tightening monetary policies, an uncertain recovery of China post COVIDlockdowns and a slowdown in the Eurozone driven by weak industrial production, worldwide demands for crude oil has showed remarkable resilience. This has been driven by continued economic growth in India and other emerging economies, steady Chinese consumptions despite the economic headwinds and solid US demand.

Global worldwide demand is estimated to have reached an all-time high in 2023 at about 102 million barrels/day, up by about 2% from 2022. This growth has held down global stocks of crude oil and refined products including both amounts stored onshore and oil-on-water, putting a floor under Brent prices, which have rebounded whenever they have touched key resistance levels.

Other bouts of volatility were registered on occasion of the resurgence of the conflict in Middle East in October 2023, culminating in Israelis military invasion of the Gaza strip. However, this rally too was short-lived given weakening fundamentals.

The decline in crude oil prices negatively affected Eni' results of operations and cash flow in 2023 compared to the previous year.

Looking forward, we believe that crude oil prices could be further negatively affected by expectations among market participants regarding a possible slowdown or a recession of the global economy possibly leading to a contraction in demand for crude oil, thus limiting the chance of a price recovery in 2024. Furthermore, we believe that the global oil market will remain well supplied due to continued production growth in non-OPEC countries and because of anticipated production increases at several international oil companies reflecting better performance and efficiency gains. Furthermore, uncertain production discipline on the part of OPEC+ countries represents a risk factor to this outlook due to the willingness of several countries (e.g. Iraq, UAE, Nigeria) to boost revenues from oil exports. For 2024, management is forecasting a Brent crude oil price of 80 \$/bbl.

Natural gas prices, especially in Europe, experienced a deeper correction than crude oil amidst acute volatility, as they were down by approximately 70% on average in 2023 compared to 2022 (from 130 €/MWh to 40€ for the spot price at the European reference hub Title Transfer Facility "TTF"; similar decreases were experienced for the Italian benchmark PSV). This decline was largely driven by global oversupplies of natural gas and development of additional liquefaction and regassification capacity which enabled the US to export record amounts towards international markets. In Europe, demand for natural gas was negatively and significantly affected by an ongoing economic slowdown, a slump in industrial production, energy savings by households and other consumers and growing competition from renewables. A milder-than-usual winter season compounded the weak fundamentals. The main source of weakness has remained the contraction of industrial production across the Eurozone, especially in Germany, which was due to relatively higher energy costs incurred by European undertakings compared to other geographies, forcing many industrial activities to decrease production or relocate to other regions. As a matter of fact, the cost of natural gas in Europe is currently running five to six times that of the US, reducing the competitiveness of many industries in Europe, including our petrochemicals business. US natural gas production, both dry gas and associated gas, has repeatedly broken record after record through the entire 2023, fueling massive export volumes thanks to rising liquefaction capacity. We believe that the global market will remain oversupplied for the foreseeable future also considering new LNG capacity additions in North America, Middle East, and Australia and, after the winter of 2023, another mild winter season in 2024. For 2024, management is forecasting a spot natural gas price for the main European benchmarks (TTF and PSV) of around 30 €/MWh equivalent to about 10-12 \$/mmBTU.

Our results of operations and cash flow are exposed to the volatility of hydrocarbons prices because we generally do not hedge our commodity exposure in the business of producing crude oil and natural gas. For 2023, we estimated that the decline in hydrocarbons prices reduced the operating profit of the E&P segment by about €5 billion and the Group net cash provided by operating activities by an estimated €3 billion.

Key consolidated financial data

		2023	2022	2021
			(€ million)
Sales from operations		93,717	132,512	76,575
Operating profit (loss)		8,257	17,510	12,341
Adjusted operating profit (Non-GAAP measure) (1)		13,805	20,386	9,664
Net profit (loss) attributable to Eni		4,771	13,887	5,821
Adjusted net profit (Non-GAAP measure) (1)		8,322	13,301	4,330
Net cash provided by operating activities		15,119	17,460	12,861
Capital expenditures		9,215	8,056	5,234
Acquisitions		2,592	3,311	2,738
Disposal of assets, consolidated subsidiaries and businesses		596	1,202	404
Shareholders' equity including non-controlling interest		53,644	55,230	44,519
Finance debt (including lease liabilities)		34,065	31,868	33,131
Net borrowings excluding lease liabilities (1)		10,899	7,026	8,987
Net profit (loss) attributable to Eni diluted	(€ per share)	1.40	3.95	1.60
Dividend per share	(€ per share)	0.94	0.88	0.86
Ratio of finance debt (including lease liabilities) to total shareholders' equity		0.63	0.58	0.74
Ratio of net borrowings excluding lease liabilities to total shareholders'
equity (leverage) (1)		0.20	0.13	0.20

(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 2023, notwithstanding a decline in hydrocarbons prices with the benchmark Brent crude oil price down by 18% year-overyear and spot prices of natural gas at European hubs down by approximately 70%, the Group reported sound, albeit decreasing financial results.

In 2023, reported operating profit was €8.26 billion, almost €9 billion lower than in 2022 due to price effects and higher extraordinary charges, net finance expense was €0.47 billion and income from investments was a positive €2.44 billion. The reported tax rate was around 52%, higher than in 2022 at 37%, due mainly to unfavorable price effects and the dilutive effect.

Net income for the year was €4.8 billion and included an inventory holding loss and identified items of about €3.5 billion. Excluding those latter items, management's most tracked performance indicator "adjusted net profit" which is a NON-GAAP measure (see page 110 for a definition and reconciliation of adjusted results to reported results) came in at €8.3 billion.

The principal components of the adjusted profit consisted of:

• €13.8 billion of adjusted operating, profit which was driven by a steady performance of the E&P segment with about €10 billion of operating profit and a significant performance of the GGP segment which delivered profit of €3.2 billion. Significant contributions were also achieved by Enilive, Plenitude and the business of oil refining, whereas the petrochemicals business incurred about €0.6 billion of operating losses driven by a demand slowdown and increased competitive pressures from overseas products because of the disadvantaged cost position of European players reflecting comparatively higher energy and environmental expenses;
• Results from equity-accounted entities and dividends from fair-valued entities contributed €1.75 billion;
• Finance expense decreased compared to the previous year to a loss of €0.44 billion due to the fact that a large portion of Eni's finance debt was at fixed rates, whereas interest income benefitted from an environment of rising yields, and financial assets held-for-trading contributed significantly because the yield curve flattened sharply in the final months 2023;
• Finally the Group underlying tax rate was approximately 44% and was calculated by excluding the above mentioned identified items and their relevant tax effect.

Those results drove a robust cash flow from operating activities of €15.1 billion, large enough to fund capital expenditures of €9.2 billion and asset acquisitions of €2 billion (net of dispositions), leaving a surplus of about €3.6 billion compared to cash returns to Eni's shareholders of about €4.8 billion (€3 billion of dividends and a stock repurchase program of €1.8 billion). As a result of those cash movements and including the repayment of lease liabilities and the incurrence of finance debt in connection with deferred payment terms agreed with certain suppliers of capital goods, GAAP finance debt was €28.7 billion at December 31, 2023, almost €2 billion higher than at the end of 2022, while lease liabilities were €5.3 billion, almost in line with 2022. The GAAP measure of indebtedness which compare gross debt to total equity was around 0.63.

Our net borrowing (Non-GAAP measure defined as finance debt less cash, cash equivalents and held-for-trading securities – see Glossary) increased by €3.9 billion to €11 billion. In spite of that increase, the management's tracked measure of financial structure – leverage (ratio of net borrowings to total equity – see glossary) came in at 0.2, remaining within our stated target range (0.15 – 0.25).

In 2023, we delivered solid operating performance and progressed our strategy. Hydrocarbons production grew by 3% to 1.529 million boe/day. We started two important reserve development projects: the Baleine oilfield development off Cote d'Ivoire and a project in Congo to produce LNG from a floating vessel which delivered its first LNG cargo at the end of February 2024. We made several exploration discoveries, the most significant being the natural gas discovery of Geng off Indonesia, which has opened a whole set of opportunities considering our strengthened position in the region, also with the acquisition of Chevron's assets in that area. In January 2024, we completed the acquisition of upstream operator Neptune Energy Group. The acquired company will complement Eni's portfolio in key areas like Indonesia, UK and Algeria; in this latter country earlier in the year we purchased bp's interests in certain natural gas fields.

GGP benefitted from some contractual renegotiations and strengthened its market position by way of continuing asset portfolio optimizations.

Plenitude has achieved the first milestone of its development program in the renewable space by reaching an installed generation capacity of 3GW.

Enilive, operational from January 1, 2023, started the international expansion of the biofuels manufacturing business by establishing a JV with a US operator to run the biorefinery of Chalmette in Louisiana and is progressing towards final investment decisions at two projects in South Korea and Malaysia in joint venture with local operators.

Despite a market downturn and a sharply increased loss, Versalis has commenced its restructuring by acquiring a controlling stake in Novamont which is a leader in the production of bioplastics.

Overall, management believes that the fundamentals of the Company have improved. For 2024, we are assuming a continued decline in European natural gas prices and stable Brent prices at 80 \$/bbl and we are planning to make about €9 billion of capital expenditures. Hydrocarbons production is expected to grow again by about 3%.

See forward guidance in the sections below.

Reported earnings

In 2023, Eni reported a net profit attributable to its shareholders of €4,771 million, driven by an operating profit of €8,257 million (against an operating profit of €17,510 million in 2022) due to lower hydrocarbons prices and a weak performance in the petrochemicals business, and lower results of investments (decrease of approximately €3 billion) also reflecting the capital gain recognized in 2022 on the divestment of our consolidated subsidiaries in Angola and establishment of the Azule Energy Holdings JV. Those negatives were partly offset by decreasing financial expenses mainly driven by higher income on cash deposits and fair value gains at financial assets held for trading due to a declining yield-curve in the final months of the year, as well as lower income taxes.

NON-GAAP measures of performance: adjusted results

Adjusted operating profit (loss) and adjusted net profit (loss) are determined by excluding from the reported results inventory holding gains or losses and identified gains and losses (pre and post-tax, respectively) that in our view do not reflect business base performance.

Adjusted operating profit (or loss) and adjusted net profit (or loss) provide management with an understanding of the results from our underlying operations and are used to evaluate our period-over-period operating performance, as management believes these provide more comparable measures as they adjust for disposals and special charges or gains not reflective of the underlying trends in our business. These Non-GAAP performance measures may also assist investors in evaluating the underlying operating performance of our business and in comparing it with the performance of other oil&gas companies, because the items excluded from the calculation of such measures can vary substantially from company to company depending upon accounting methods, management's judgment, book value of assets, capital structure and the method by which assets were acquired, among other factors. Nevertheless, other companies may adopt different criteria in identifying underlying results and therefore our measure of adjusted operating profit (loss) and adjusted net profit (loss) may not be comparable to the adjusted measures presented by other companies.

In 2023, identified items amounted to a total positive adjustment of €3,551 million in net profit and of €5,548 million in operating profit, including an inventory pre-tax loss of €562 million (€402 million post-tax) relating to oil and refined products. Those items mainly comprised: (i) impairment losses of €1 billion in the Exploration & Production segment driven by downward reserves revisions and a lowered outlook for natural gas prices; (ii) impairment losses of chemical plants to reflect a reduced profitability outlook following worsening industry fundamentals (€0.4 billion); (iii) the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows in the Refining business (€0.4 billion); (iv) environmental and remediation provision of €0.65 billion; (v) the mark-to-market of commodity derivatives lacking the formal criteria to be classified as hedges under applicable accounting standards (€1.3 billion); (vi) a €0.7 billion charge relating to the natural gas inventory held for trading purposes reflecting the timing difference between the moment the sale occurs (typically during the peak winter season) and the incurrence of the supply cost (typically during summer months) and is determined by the difference between the supply cost net of hedging effects and the weighted average cost of supplies incurred in the quarter which is utilized to value gas inventory for IFRS accounting. These charges were offset by a gain of €0.8 billion in connection with the sale of a 49.9% interests and consequent loss of control of Eni's subsidiaries managing the TTPC/Transmed pipelines and the relevant transportation rights of natural gas volumes imported from Algeria following the agreement to estabilish a joint venture with Snam SpA, which also included the fair-value revaluation of the interest retained by Eni in the venture (approximately 50% of the overall gain). 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 prof it (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,
	2023	2022	2021
		(€ million)
Identified gains and losses of operating profit (loss)	4,986	3,440	(1,186)
- environmental charges	648	2,056	271
- impairment losses (impairments reversal), net	1,802	1,140	167
- impairment of exploration projects		2	247
- net gains on disposal of assets	(11)	(41)	(100)
- risk provisions	39	87	142
- provision for redundancy incentives	158	202	193
- commodity derivatives	1,255	(389)	(2,139)
- exchange rate differences and derivatives	(16)	149	183
- other	1,111	234	(150)
Net finance (income) expense	30	(127)	(115)
of which:
- exchange rate differences and derivatives reclassified to operating profit (loss)	16	(149)	(183)
Net (income) expense from investments	(698)	(2,834)	851
of which:
- gain on the SeaCorridor deal	(834)
- gain on the divestment interest of Vår Energi		(448)
- net gains on the divestment of Angolan assets		(2,542)
Income taxes	(1,180)	(683)	19
Total non core gains and losses of net profit (loss)	3,138	(204)	(431)
Attributable to:
- non-controlling interest	(11)	(19)
- Eni's shareholders	3,149	(185)	(431)

The item "other charges/ (gains)" mainly related to the GGP segment for about €0.8 billion. See the segmental review below.

The Group underlying performance – i.e. excluding the identified gains and losses as well as the inventory holding profit – was an adjusted operating profit of €13,805 million compared to €20,386 million in 2022, down by approximately 32% or €6.58 billion. This performance reflected the lower contribution by the E&P segment (down by €6.54 billion) due to a reduction in crude oil and natural gas prices that impacted realizations on equity production and the derecognition of the subsidiaries operating in Angola which were contributed to the Azule Energy Holdings JV effective August 1st 2022, the underperformance of the Chemical business (with a loss of €0.6 billion) due to a slowdown in demand and cost disadvantages, and finally a significantly deteriorated refining scenario leading to a sharp contraction of Refining adjusted operating profit (down by €1 billion). These negative trends were offset by the Global Gas and LNG portfolio segment delivering a significant performance with a profit of €3.2 billion (up by €1.2 billion) leveraging on portfolio optimizations, contract renegotiations and a settlement of an arbitration, as well as by increasis at Enilive and Plenitude & Power.

Excluding identified items and the inventory evaluation profit, adjusted net profit for 2023 was €8,322 million, a €4,979 million decrease compared to 2022. The result was driven by a lower operating performance and results from equity accounted entities. The Group tax rate, excluding identified items (see paragraph "Taxes" of this item), was 44% and was higher than in 2022 (39% in 2022) as a result of the impact of the UK energy profit levy (effective from the third quarter 2022), adverse scenario effects and the impact of E&P non-deductible expenses particularly the write-off of exploration expenses. This was partly offset by a higher proportion of the taxable profit earned by Italian subsidiaries.

The table below provides a reconciliation of those Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS.

	Year ended December 31,
	2023	2022	2021
	(€ million)
GAAP operating profit (loss)	8,257	17,510	12,341
Inventory holding (gains) and losses	562	(564)	(1,491)
Identified net (gains) losses	4,986	3,440	(1,186)
Total net items in operating profit	5,548	2,876	(2,677)
Non-GAAP operating profit (loss)	13,805	20,386	9,664
GAAP net profit (loss)	4,771	13,887	5,821
Inventory holding (gains) and losses, post tax	402	(401)	(1,060)
Identified net (gains) losses, post tax	3,149	(185)	(431)
Total net items in net profit	3,551	(586)	(1,491)
Non-GAAP net profit (loss)	8,322	13,301	4,330

Trading environment

	2023	2022	2021
Average price of Brent dated crude oil in U.S. dollars (1)	82.62	101.19	70.73
Average price of Brent dated crude oil in euro(2)	76.43	96.09	59.8
Average EUR/USD exchange rate(3)	1.081	1.053	1.183
Standard Eni Refining Margin (SERM)(4)	10.1	8.5	(0.9)
Euribor - three month euro rate % (3)	3.43	0.35	(0.55)

(1) Price per barrel. Source: Platt's Oilgram.

(2) Price per barrel. Source: Eni's calculations based on Platt's Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).

(3) Source: ECB.

(4) In \$/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations, as difference between the cost of a barrel of Brent crude oil and the value of the products obtained according to the standard yields of the Eni refining system, less expenses for industrial utilities (mainly energy expenses indexed at the cost of natural gas).

Group profit and loss

The table below sets forth a summary of Eni's profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS. For the disclosure on 2022 Group results compared to 2021 see the Annual Report on Form 20-F 2022, filed to the SEC on April 5, 2023.

	Year ended December 31,
	2023	2022	2021
	(€ million)
Sales from operations	93,717	132,512	76,575
Other income and revenues (1)	1,099	1,175	1,196
Total revenues	94,816	133,687	77,771
Operating expenses	(77,221)	(105,497)	(58,716)
Other operating (expense) income	478	(1,736)	903
Depreciation, depletion and amortization	(7,479)	(7,205)	(7,063)
Impairment reversals (impairment losses) of tangible and intangible and right of
use assets, net	(1,802)	(1,140)	(167)
Write-off of tangible and intangible assets	(535)	(599)	(387)
OPERATING PROFIT (LOSS)	8,257	17,510	12,341
Finance income (expense)	(473)	(925)	(788)
Income (expense) from investments	2,444	5,464	(868)
PROFIT (LOSS) BEFORE INCOME TAXES	10,228	22,049	10,685
Income taxes	(5,368)	(8,088)	(4,845)
Net profit (loss)	4,860	13,961	5,840
Attributable to:
- Eni's shareholders	4,771	13,887	5,821
- Non-controlling interest	89	74	19

(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.

Analysis of the line items of the prof it 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,
	2023	2022	2021
	(€ million)
Exploration & Production	23,903	31,194	21,742
Global Gas & LNG Portfolio	20,139	48,586	20,843
Enilive, Refining and Chemicals	52,558	59,178	40,374
Plenitude & Power	14,256	20,883	11,187
Corporate and other activities	1,972	1,886	1,698
Consolidation adjustments	(19,111)	(29,215)	(19,269)
SALES FROM OPERATIONS	93,717	132,512	76,575

2023 compared to 2022. Sales from operations (revenues) for 2023 (€93,717 million) decreased by €38,795 million from 2022 (or down by 29.3%) reflecting a downturn in the commodity environment which took place in 2023 (with a negative impact of approximately €40 billion) and a decline in volume sold in the Exploration & Production segment (with negative impact of €2.2 billion) mainly attributable to the derecognition of Eni's subsidiaries operating in Angola from August 1, 2022 thus contributing for eight months to the 2022 revenues, and in the GGP segment (an impact of -€7.7 billion) due to sharply lower offtakes related to supply contracts from Russia. The appreciation of 3% of the average EUR vs USD exchange rate in 2023 reduced revenues in the E&P segment by an estimated €0.7 billion. These negatives were partly offset by the increase of €5 billion due to higher traded volumes activities in the Refining business.

The detailed effects of scenario trends as well as volume/mix on the changes (2023 vs. 2022) in sales from operations are reported in the table below.

change	of which:	price effects	volume/mix
(€ billion)
(7.3)		(5.1)	(2.2)
(28.4)		(20.8)	(7.7)
(5.3)		(10.8)	5.5
(2.0)		(1.2)	(0.8)
(6.6)		(5.4)	(1.2)

Other income and revenues

2023 compared to 2022. Eni's other income and revenues amounted to €1,099 million in 2023 and include the share of lease repayments debited to joint operators in Eni-led upstream projects (€121 million), as well as revenues from patents, licenses and royalties.

b) Operating expenses

The table below sets forth the components of Eni's operating expenses for the periods indicated.

	Year ended December 31,
	2023	2022	2021
	(€ million)
Purchases, services and other	73,836	102,529	55,549
Impairment losses (impairment reversals) of trade and other receivables, net	249	(47)	279
Payroll and related costs	3,136	3,015	2,888
Operating expenses	77,221	105,497	58,716

2023 compared to 2022. Operating expenses for 2023 (€77,221 million) decreased by €28,276 million compared to the prior year, down by 26.8%, primarily reflecting the decrease of purchases, services and other costs (€28,693 million; down by 28.0% vs. 2022) mainly due to lower supply costs of hydrocarbons (natural gas under long-term supply contracts, refinery and chemical feedstocks).

Payroll and related costs (€3,136 million) increased by €121 million from 2022 (up by 4%) mainly due to extraordinary measures taken to help the disposable income of the Group employees in Italy through the award of a lump sum and other benefits, which was implemented at the end of 2023.

c) Depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off

The table below sets forth a breakdown of depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off for the periods indicated.

	Year ended December 31,
	2023	2022	2021
		(€ million)
Exploration & Production	6,148	6,017	5,976
Global Gas & LNG Portfolio	233	217	174
Enilive, Refining and Chemicals	524	506	512
Plenitude & Power	466	358	286
Corporate and other activities and impact of unrealized intragroup profit elimination	108	107	115
Total depreciation, depletion and amortization	7,479	7,205	7,063
Impairment losses (impairment reversals) of tangible and intangible assets, goodwill and right
of use assets, net	1,802	1,140	167
Write-off of tangible and intangible assets	535	599	387
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
assets	9,816	8,944	7,617

2023 compared to 2022. In 2023, depreciation, depletion and amortization charges (€7,479 million) increased by €274 million from 2022, mainly in the Exploration & Production segment following start-ups and ramp-ups of new projects, partly offset by the appreciation of the euro against the US dollar, as well as certain plants start-ups in the Plenitude & Power segment.

In 2023, the Group recorded impairment losses at property, plant and equipment for a total amount of €1,802 million, out of which €1,037 million were driven by forecasts of lower natural gas prices and downward reserve revisions, affecting properties in Italy, the USA and Turkmenistan, net of a revaluation of an oilfield in Congo due to better performance. The Enilive, Refining and Chemical segment incurred €764 million of impairment losses driven by a reduced profitability outlook in the petrochemicals segment resulting in the book values of plants in the intermediates, styrene's and elastomers segments being marked down to their lower recoverable amounts recognizing an impairment loss of €405 million, and 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.

Write-off of tangible and intangible assets amounted to €535 million and mainly related to the E&P segment as capitalized costs of suspended exploratory wells were expensed through profit due to the negative assessment of recoverable reserves or economic feasibility of exploration projects in Egypt, Mexico, Mozambique, Morocco, the United Arab Emirates and Lebanon, as well as exploration mineral rights because the Company decided to stop pursuing the underlying initiatives.

d) Operating prof it (loss) by segment

The table below sets forth Eni's operating profit by business segment for the periods indicated.

		Year ended December 31,
	2023	2022	2021
	(€ million)
Exploration & Production	8,549	15,963	10,113
Global Gas & LNG Portfolio	2,431	3,730	899
Enilive, Refining and Chemicals	(1,397)	460	45
Plenitude & Power	(464)	(825)	2,355
Corporate and other activities	(943)	(1,956)	(863)
Impact of unrealized intragroup profit elimination	81	138	(208)
Operating profit (loss)	8,257	17,510	12,341

Exploration & Production. In 2023, the Exploration & Production segment reported an operating profit of €8,549 million, with a decrease of €7,414 million compared to the operating profit of €15,963 million reported in 2022. The decrease was driven by lower prices of hydrocarbons reflecting an unfavorable commodity environment, the derecognition of the Angolan subsidiaries which took effect from August 1, 2022, therefore impacting year-over-year comparability of E&P operating profit. Finally the appreciation of the EUR vs USD exchange rate negatively affected the operating profit by an estimated €0.44 billion. In 2023, Eni's average prices for crude oil and natural gas liquids decreased on average by 15.4%, compared to a decrease of 18.4% recorded in international oil prices for the Brent market benchmark, with the difference due to Eni's production mix. Eni's average natural gas prices decreased by 21.6%, better than the decline in European or other market benchmarks as the Group natural gas equity production is mostly indexed to the price of crude oil.

In reviewing the performance of the Company's business segments and with a view to better explaining year-on-year changes in segment 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 2023, identified gains and losses included impairment losses of €1,037 million, credit loss provisions (€129 million, which is reported in the item "other" charges and gains) just for the part of the expected loss related to temporary conditions of the receivables which are expected to reverse in future periods or because another transaction was pending with the debtor, environmental provisions (€81 million) and provisions for redundancy incentives (€40 million).

Excluding those items, the E&P segment reported a Non-GAAP operating profit of €9,934 million, with a decrease of €6,535 million from 2022, down by 39.7%, driven by lower realizations in US dollars at equity production the establishment of the Azule Energy Holdings JV as explained above, and a negative impact of movements in the EUR vs USD exchange rate.

				volume/mix
	change	of which:	price effects	effects
		(€ million)
Change in E&P Non-GAAP operating profit (loss) 2023 vs. 2022	(6,535)		(4,889)	(1,646)
		Year ended December 31,
		2023	2022	2021
Exploration & Production
GAAP operating profit (loss)		8,549	15,963	10,113
Impairment losses (impairment reversals), net		1,037	432	(1,244)
Net gains on disposal of assets		2	(27)	(77)
Environmental provisions		81	30	60
Risk provisions		7	34	113
Reclassification of currency derivatives and translation effects to management
measure of business performance		62	(54)	(3)
Write off of exploration projects		0	2	247
Other		196	89	131
Total identified gains and charges		1,385	506	(773)
Non-GAAP operating profit (loss)		9,934	16,469	9,340

Global Gas & LNG Portfolio (GGP)

In 2023, the GGP segment reported an operating profit of €2,431 million compared to a profit of €3,730 million in 2022. The decrease was negatively affected by movements in fair-valued commodity derivatives (from a gain of around €1.8 billion in 2022 to a loss of €97 million in 2023), 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 natural gas prices and volatility which negatively affected optimization and trading opportunities, partly offset by the gains recognized on contract renegotiations and the settlement of an arbitration.

In reviewing the performance of the Company's GGP business 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 to IFRS. We also entered as part of our ordinary activities 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 the 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 2022, those fair value effects on commodity derivatives amounted to a gain of €1.8 billion due to certain fixed-price forward sales which fair values reflected a rapid decrease in natural gas prices at year end.

In 2023, identified items excluded a loss 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 segment reported a Non-GAAP operating profit of €3,247 million, with an increase of €1,184 million from 2022. This improvement was mainly driven by the benefits associated with contract renegotiations and a favorable settlement of an arbitration. Furthermore, the segment's margins were supported by continuous initiatives of portfolio optimizations, which allowed the business to take advantage of the volatility in natural gas and LNG markets, while managing the underlying risks and ensuring supplies to customers. However, gains recorded in connection with portfolio optimizations were lower than in 2022 because the level of both natural gas prices and volatility was significantly lower.

	change	of which:	price effects	contract renegotiations and risk provisions
	(€ million)
Change in GGP Non-GAAP operating profit (loss) 2023 vs. 2022	1,184		(377)	1,561

	Year ended December 31,
	2023	2022	2021
Global Gas & LNG Portfolio	(€ million)
GAAP operating profit (loss)	2,431	3,730	899
Impairment losses (impairment reversals), net	(1)	(12)	26
Provision for redundancy incentives	4	4	5
Fair value gains/losses on commodity derivatives	97	(1,805)	(207)
Reclassification of currency derivatives and translation effects to
management measure of business performance	(105)	244	206
Other	821	(98)	(349)
Total identified gains and charges	816	(1,667)	(319)
Non-GAAP operating profit (loss)	3,247	2,063	580

Enilive, Refining and Chemicals. In 2023, the Enilive, Refining and Chemicals segment reported an operating loss of €1,397 million, compared to an operating profit of 460 million in 2022, a decrease of €1,857 million, driven by a margin and volume downturn in the Chemical business, lower refining margins and a one-billion swing in the accounting value of oil and products inventories due lower prices as the value of inventories is stated at the weighted-average cost of supplies of the last quarter of the year.

The main item excluded from GAAP operating profit in determining the Non-GAAP measure of profitability 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 writedown 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.

In addition to the inventory holding profit (or loss), the identified items of this segment for the year 2023 comprised environmental provisions of €373 million, impairment losses of chemical plants to reflect a reduced profitability outlook (€405 million), as well as the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows in the Refining business (€359 million).

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 the inventory holding gain (or loss) 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 and Refining business reported a Non-GAAP operating profit of €1,169 million (an operating profit of €2,183 million in 2022), while the Chemical business reported a Non-GAAP operating loss of €614 million (a loss of €254 million in 2022).

In 2023, Eni's refining business with a Non-GAAP operating profit of €441 million was negatively affected by narrowing spreads between heavy/sour crude qualities vs light/sweet crudes like Brent, due to lower supplies of the former in the Mediterranean area as a result of the sanction regime against Russia's crude oil and production cuts implemented by OPEC+ countries. Lower supplies of those crude qualities negatively affected the profitability of Eni's complex refineries by reducing the cost advantage in processing low quality crudes that normally trade at a discount vs. Brent to reflect their lower yields of valuable fuels. Therefore, in an environment of narrowing differentials Eni's complex refineries stand to be hit. Lower plant energy expenses driven by a fall in European prices help soften the reduced margins on throughput.

The reduction in the results of the refining business line was partly offset by better performance of Enilive (Non-GAAP operating profit of €728 million) and increased sales volumes of biofuels (up by 48%).

change	of which:	price effects	volume/mix/cost measures
(1,014)		(959)	(55)
			(€ million)

The Chemical business reported a non-GAAP operating loss of €614 million in 2023, compared to a loss of €254 million in 2022 due to lower demand across all business segments driven by a slowdown in the macro environment and comparatively higher production costs in Europe for energy inputs, which reduced the competitiveness of Versalis production with respect to US and Asian players.

	change	of which:	price effects	volume/mix/cost measures
		(€ million)
Change in Chemicals' Non-GAAP operating profit (loss) 2023
vs. 2022	(360)		(333)	(27)

	Year ended December 31,
	2023	2022	2021
Enilive, Refining and Chemicals	(€ million)
GAAP operating profit (loss)	(1,397)	460	45
(Profit) loss on inventory	604	(416)	(1,455)
Environmental provisions and other costs	373	962	150
Impairment losses (impairment reversals), net	764	717	1,342
Net gains on disposal of assets	(9)	(10)	(22)
Risk provisions	19	52	(4)
Provision for redundancy incentives	46	46	42
Fair value gains/losses on commodity derivatives	14	4	50
Reclassification of currency derivatives and translation effects to management measure of business performance	24	(33)	(14)
Other	117	147	18
Total identified gains and charges	1,952	1,469	107
Non-GAAP operating profit (loss)	555	1,929	152
- Enilive	728	672	n.a.
- Refining	441	1,511	n.a.
- Chemicals	(614)	(254)	198

Plenitude & Power

In 2023, this segment reported an operating loss of €464 million, an improvement of €361 million compared to the loss of €825 million of the previous year, mainly due to the positive performance of the gas retail business and leveraging on the integrated business model which benefited from the improved pricing dynamics.

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 loss of €1,144 million.

Excluding those charges, the Plenitude & Power segment reported a Non-GAAP operating profit of €681 million, with an increase of €66 million from 2022, or 10.7%. The retail gas and power business and the renewables business managed by Plenitude reported a Non-GAAP operating profit of €515 million, up by €170 million year-on-year driven by higher margins at the retail business in Italy leveraging cross-selling opportunities of the integrated value chain, increased sales volumes of renewables electricity and better results in France.

The power business reported an adjusted operating profit of €166 million (down by €104 million) due to a deteriorated price scenario in the wholesales electricity market and lower revenues from participating to the despatching services market.

Corporate and Other activities. These activities are mainly cost centers comprising holdings, financing and treasury activities in support of operating subsidiaries, central functions like legal counselling, 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, from the fourth quarter of 2023 and effective January 1, 2023, the results of CCUS and Agribusiness of Eni have been included in the "Corporate and other activities" reporting segment whereas previously they were reported as part of the Exploration & Production segment results. Comparative reporting periods of 2022 have been restated accordingly; however the overall impact was immaterial. 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 €943 million in 2023 compared with a loss of €1,956 million reported in 2022. The reduced loss reflected lower environmental charges (€193 million in 2023 compared to more than €1 billion in 2022 which is mainly referred to reliable estimate of the future costs of the reclamation of groundwater) mainly relating to lower environmental provisions taken at dismissed Italian industrial hubs. Those charges were treated as identified items. Net of those charges, expenses of support departments were almost stable.

e) Net f inance expenses

The table below sets forth a breakdown of Eni's net financial expenses for the periods indicated:

	Year ended December 31,
	2023	2022	2021
		(€ million)
Income (expense) on derivative financial instruments	(61)	13	(306)
of which - Derivatives on exchange rate	(63)	(70)	(322)
- Derivatives on interest rate	2	81	16
- Options		2
Exchange differences, net	255	238	476
Finance expense from banks on short and long-term debt	(874)	(635)	(569)
Interest expense for lease liabilities	(267)	(315)	(304)
Interest income due to banks	356	57	4
Net income from financial assets measured at fair value through profit or loss	284	(55)	11
Finance expense due to the passage of time (accretion discount)	(341)	(199)	(144)
Other finance income and expense, net	81	(67)	(24)
	(567)	(963)	(856)
Finance expense capitalized	94	38	68
NET FINANCE EXPENSES	(473)	(925)	(788)

In 2023, net finance expenses were €473 million, €452 million lower than in 2022. The reduction in net financial expense in 2023 compared to 2022 was due to the Company having taken out a large part of its loans at fixed rates, whereas interest income from cash deposits benefited from a rising yield environment in 2023, whereas fair-valued financial assets held for trading recorded significant gains because the yield curve flatted in the final months of 2023.

f) Net income from investments

The table below sets forth a breakdown of Eni's net income from investments for the periods indicated:

	Year ended December 31,
	2023	2022	2021
		(€ million)
Share of gains (losses) from equity-accounted investments	1,336	1,841	(1,091)
Dividends	255	351	230
Net gains (losses) on disposals	430	483	1
Other income (expense), net	423	2,789	(8)
	2,444	5,464	(868)

In 2023 the Group reported a net profit from investments of €2,444 million, down by about €3 billion from 2022 due the gain of €2,789 million recognized in 2022 mainly on the divestment of Eni's subsidiaries in Angola which were contributed to the newly-established Azule Energy JV, operational from August 1, 2022. Eni's share of profits generated by equity-accounted investments was €1,336 million and was mainly driven by profits in the Exploration&Production segment (€1,009 million), the Enilive, Refining and Chemicals segment (€343 million) and the GGP segment (€49 million), partly offset by losses at Plenitude & Power segment (€55 million) and Corporate and other activities (€10 million) segment. Eni's share of profits from equityaccounted investments declined by about €0.5 billion from 2022 due to price effects, partly offset by the full contribution of the Azule Energy JV. A break-down of profits earned for the main investments is provided below:

• (i) in E&P, we recognized a profit of €356 million at the Vår Energi, a decrease of €335 million from 2022 due the lower hydrocarbons prices;
• (ii) the Enilive and Refining ADNOC Refining&Trading associate, where we recognized a profit of €418 million, down from €529 million in the previous year due to lower refining margins;
• (iii) the E&P Azule Energy Holdings joint venture, where we recognized a profit of €653 million;
• (iv)the E&P Mozambique Rovuma Venture SpA associate for €47 million;
• (v) the GGP SeaCorridor associate for €49 million;
• (vi)the joint venture Saipem, where we recognized a profit of €56 million, reverting a prior-year loss due the effects of an ongoing restructuring and improved end-markets.

Dividends of €255 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 (€179 million), and Saudi European Petrochemical Co (€55 million).

A gain of €420 million was recorded on the divestment of a 49.9% stake in the equity interests of Eni's subsidiaries managing the TTPC/Transmed pipelines following the deal with Snam and other non-strategic assets. The retained interests in the newly-established joint venture was aligned to fair value with a gain through profit and loss of €414 million included in the line item "other income".

g) Taxes

In 2023, income taxes decreased by €2,720 million to €5,368 million and compared to the pre-tax profit of €10,228 million resulted in a tax rate of 52.5% (compared to 36.7% in 2022), driven by unfavorable price effects and the negative impact of the deal involving the establishment of Azule Energy Holdings JV on the 2023 tax rate, whereas the 2022 tax rate benefitted from Angolan activities being consolidated until loss of control (August 1, 2022).

In 2022, income taxes included an extraordinary solidarity tax for the year 2022 (€1,036 million) enacted in Italy by Law No. 51 of May 20, 2022, as well as the UK Energy profit levy. Furthermore, the 2022 income taxes included an extraordinary contribution as enacted by Law No. 197 of December 29, 2022 (Italian 2023 Budget Law) calculated on the 2022 taxable income, determined considering the distribution of certain revaluation reserves of the parent company.

The adjusted tax rate, which exclude the impact of identified gains and losses, is the measure of tax rate tracked by management, and increased by 5 percentage points in 2023 compared to 2022, to 44.4% due to the impact of the UK energy profit levy (effective from the third quarter 2022), adverse price effects and the impact of E&P non-deductible expenses particularly the write-off of exploration expenses, as well as the transaction involving Azule Energy Holdings JV. Those negatives were partly offset by a higher proportion of the taxable profit earned by Italian subsidiaries, which are subject to a lower tax rate (excluding the solidaristic, one-off contributions mentioned above).

In 2023 the uptrend in hydrocarbons and electricity prices that began in 2021 driven by the post-Covid economic recovery, has moderated due to a global slowdown and an uncertain recovery in China. However, the costs of fuels and energy has remained elevated, particularly in Europe, and has significantly and adversely affected businesses' profit margins and households' disposable income. In response to high energy costs, several jurisdictions where we operate have refrained from reducing the fiscal take on the energy sector. In the UK a temporarily windfall tax on oil companies' profits has been increased by ten percentage points in 2023 compared to the initial rate of twenty-five percentage points in 2022. In Italy, a solidaristic contribution enacted at the end of 2022 by the Italian 2023 budget law, marking the second of this type of measure in the same year, was confirmed in its original formulation without exempting certain equity reserves that Eni believed to lack correlation with the taxable income from operations. Therefore, the amount accrued in 2022 for this latter Italian solidaristic contribution of €1.1 billion did not undergone any adjustment. As a result of those windfall taxes, the Group incurred a cash-out of about €0.6 billion in 2023, after having disbursed about €1.2 billion in 2022; part of the payment of the €1.1 billion Italian solidaristic contribution has been deferred to 2024 thanks to certain implementing rules (€0.45 billion).

Liquidity and capital resources

Eni's cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and share repurchases over the past three years were financed primarily by a combination of funds generated from operations, issues of equity investments (hybrid bonds) and divestments of property, plant and equipment and investments or the reimbursement of operating financing receivables owed to Eni by unconsolidated entities. 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,
	2023	2022	2021
	(€ million)
Net profit (loss)	4,860	13,961	5,840
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	7,781	4,369	8,568
- net gains on disposal of assets	(441)	(524)	(102)
- dividends, interest, taxes and other changes	5,596	8,611	5,334
Changes in working capital related to operations	1,811	(1,279)	(3,146)
Dividends received by equity investments	2,255	1,545	857
Taxes paid	(6,283)	(8,488)	(3,726)
Interests (paid) received	(460)	(735)	(764)
Net cash provided by operating activities	15,119	17,460	12,861
Capital expenditures	(9,215)	(8,056)	(5,234)
Acquisition of investments and businesses	(2,592)	(3,311)	(2,738)
Disposals of consolidated subsidiaries, businesses, tangible and intagible assets
and investments	596	1,202	404
Other cash flow related to investing activities	(348)	2,361	289
Net cash inflow (outflow) related to financial activities	2,194	786	(4,743)
Changes in short and long-term finance debt	315	(2,569)	(244)
Repayment of lease liabilities	(963)	(994)	(939)
Dividends paid, share repurchases and changes in minority interest and reserves	(4,882)	(4,841)	(2,780)
Net issue (repayment) of perpetual hybrid bond	(138)	(138)	1,924
Effect of changes in consolidation and exchange differences of cash and cash
equivalent	(62)	16	52
Net increase (decrease) in cash and cash equivalent	24	1,916	(1,148)
Cash and cash equivalent at the beginning of the year	10,181	8,265	9,413
Cash and cash equivalent at year end	10,205	10,181	8,265

	Year ended December 31,
	2023	2022	2021
Net cash provided by operating activities	15,119	17,460	12,861
Capital expenditures	(9,215)	(8,056)	(5,234)
Acquisitions of investments and businesses	(2,592)	(3,311)	(2,738)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets
and investments	596	1,202	404
Other cash flow related to capital expenditures, investments and divestments	(348)	2,361	289
Repayment of lease liabilities	(963)	(994)	(939)
Net borrowings (1) of acquired companies	(234)	(512)	(777)
Net borrowings (1) of divested companies	(155)	142
Exchange differences on net borrowings and other changes	(1,061)	(1,352)	(429)
Dividends paid, share repurchases and changes in minority interest and reserves	(4,882)	(4,841)	(2,780)
Net issue (repayment) of perpetual hybrid bond	(138)	(138)	1,924
Change in net borrowings(1) before IFRS 16 effects	(3,873)	1,961	2,581
Repayment of lease liabilities	963	994	939
Inception of new leases and other changes	(1,348)	(608)	(1,258)
Change in net borrowings after IFRS 16 effects (1)	(4,258)	2,347	2,262
Net borrowings (1) at the beginning of the year	11,977	14,324	16,586
Net borrowings (1) at year end	16,235	11,977	14,324

(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 2023, adjustments to reconcile the net profit reported in the year to net cash provided by operating activities mainly related to depreciation, depletion, amortization, net impairment charges and results of equity-accounted entities for €7,781 million. Adjustments to net profit also included accrued income taxes (€5,368 million) and net interest expense (€483 million), which were partly offset by amounts actually paid (€6,283 million and €460 million, respectively).

The dividends received by equity-accounted investments of €2,255 million mainly related to Vår Energi, Azule Energy Holdings, and Adnoc R&T, where other dividends recorded through profit of €255 million mainly related to Nigeria LNG.

a) Changes in working capital related to operations

In 2023, working capital generated an inflow of €1,811 million. This was mainly due to the decrease in the book value of oil, natural gas and refined products inventories accounted for under the weighted-average cost method, as well as a negative change in the fair value of commodity derivatives. Those inflows partly offset corresponding amounts recognized in the profit and loss account because the negative change in the book values of inventories is debited to profit and loss, and losses in the fair value of non-hedging commodity derivatives are charged to profit and loss. Other changes reflected the negative inflow(- €1,501 million) due to the balance between trade receivables collected (€3,322 million) and trade payables paid (-€4,823 million), which was affected by a lower amount of trade receivables factored with financing institutions, having the due date beyond the closing date of the financial statements, for €0.5 billion, as well as an increase of overdue trade receivables in Egypt.

	Year ended December 31,
	2023	2022	2021
	(€ million)
Exploration & Production	7,133	6,252	3,824
Global Gas & LNG Portfolio	16	23	19
Enilive, Refining and Chemicals	982	878	728
Plenitude & Power	740	631	443
Corporate and other activities	363	276	224
Impact of unrealized intragroup profit elimination	(19)	(4)	(4)
Capital expenditures	9,215	8,056	5,234
Acquisitions of investments and businesses	2,592	3,311	2,738
	11,807	11,367	7,972
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets
and investments	(596)	(1,202)	(404)

Capital expenditures totaled €9,215 million and €8,056 million, respectively in 2023 and in 2022.

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 €2,592 million mainly related to the acquisition of bp's natural gas activities in Algeria, the Chevron interest in the Indonesian assets, the interest in the St. Bernard (Chalmette) biorefinery in US, the purchase of the remaining participating interest in Novamont, the Plenitude's renewable assets, and the final price installment of the acquisition of PLT group made late in 2022. These outflows were partly offset by the divestment of a 49.9% stake in the equity interests of Eni's subsidiaries managing the TTPC/Transmed pipelines following the deal with Snam and other non-strategic assets.

b) Dividends paid, share repurchases and changes in non-controlling interests and reserves

In 2023, dividends paid and changes in non-controlling interests and reserves (€3,082 million) related to the dividends paid to Eni shareholders (€3,046 million which comprised two quarterly installments of the 2022 dividend for about €1.5 million and the first and the second quarterly installment of the 2023 dividend of €0.22 per share each, amounting to €1.5 billion). As part of the 2023 buy-back program, the company purchased own shares for an amount of €1,803 million.

As of March 5, 2024, the 2023 buy-back program was completed with an overall amount of 153.5 million shares purchased for a cash outlay of €2,200 million.

Financial condition

Management assesses the Group's capital structure and capital 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) 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.

Financial assets measured at fair value through profit or loss constituting part of the Group's liquidity reserves amounted to €6.8 billion as of end of 2023 and were accounted as mark-to-market financial instruments. Of this amount, fixed income securities issued by industrial companies and financial institutions were €5.2 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". Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow (mainly cash deposits established as a collateral of derivative transactions).

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 (leverage) to assess Eni's capital structure, to analyze whether the ratio between finance debt and shareholders' equity is well balanced compared to industry standard s and to track management's short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage 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 debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to leverage is the ratio of total debt to shareholders' equity (including non-controlling interest). Eni's presentation and calculation of net borrowings and leverage may not be comparable to other companies.

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

As of December 31,
	2023			2022
Short	Long		Short	Long
term	term	Total	term	term	Total
7,013	21,716	28,729	7,543	19,374	26,917
1,128	4,208	5,336	884	4,067	4,951
(10,193)		(10,193)	(10,155)		(10,155)
(6,782)		(6,782)	(8,251)		(8,251)
(855)		(855)	(1,485)		(1,485)
(9,689)	25,924	16,235	(11,464)	23,441	11,977

	As of December 31,
	2023	2022
	(€ million)
Shareholders' equity including non-controlling interest as per Eni's Consolidated Financial
Statements prepared in accordance with IFRS	53,644	55,230
Ratio of finance debt including lease liabilities to total equity	0.63	0.58
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to
total equity	(0.33)	(0.36)
Ratio of net borrowing to total equity	0.30	0.22
Ratio of net borrowing excluding lease liabilities to total equity	0.20	0.13

125

At December 31, 2023, total finance debt of €28,729 million consisted of €7,013 million of short-term debt (including the portion of long-term debt due within twelve months equal to €2,921 million) and €21,716 million of long-term debt. At the same date, lease liabilities were €5,336 million (short-term portion €1,128 million).

Total finance debt included unsecured bonds for €17,684 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €2,821 million (including accrued interest and discount).

Eni has established with financing institutions a sustainability-linked framework, on which basis the Group may issue securities and obtain financing which costs are indexed to the achievement of the following sustainability targets: (i) net carbon footprint upstream (GHG emission Scope 1 and 2) equal to or less than 5.2 million tons of CO2 equivalent by December 31, 2025; (ii) renewable energy installed capacity of at least or more than 5 GW December 31, 2025. In case the Company misses those targets, a step-up mechanism will be applied, increasing the interest cost.

As part of this framework, in 2023 Eni has issued two sustainability-linked bonds: a €2,000 million bond placed among retail investors and a €750 million bond as part of the Euro Medium Term Notes program reserved to institutional investors.

In addition, Eni placed a sustainability-linked senior unsecured convertible bond for a total nominal amount of €1,000 million.

In 2023, net borrowings including lease liabilities amounted to €16,235 million, representing a €4,258 million increase from 2022 driven by a reduction in net cash provided by operating activities.

IFRS 16 lease liabilities amounted to €5,336 million in 2023 (€4,951 million in 2022) and mainly related to the leased FPSO vessels relating to the offshore project OCPT in Ghana and in Area 1 off Mexico, as well as several minor assets like motorway concessions, land leases, service station leased for petroleum products marketing activities, as well as leases of vessels for shipping activities, leased buildings and the car fleet dedicated to the business of car sharing. The IFRS 16 lease liabilities included €480 million pertaining to joint operators in Eni-led upstream unincorporated joint ventures, which are expected to be recovered through a partner-billing process.

Net borrowings excluding the lease liabilities, which is the Non-GAAP measure of financial condition mostly tracked by management would amount to €10,899 million, up by €3,873 million compared to December 31, 2022.

The ratio of finance debt to total equity was 0.63 at 2023 year-end, including the IFRS 16 lease liability (0.58 at 2022 yearend). Total equity of €53,644 million decreased by €1,586 million from December 31, 2022. This was due to the net profit for the period (€4,860 million), the negative foreign currency translation differences (€2,010 million) reflecting the appreciation of the US dollar vs. the euro as of December 31, 2023 vs. December 31, 2022, the positive change in the cash flow hedge reserve of €541 million reflecting trends in gas prices, partly offset by the payment of dividends to Eni shareholders (two tranches of the 2022 dividend for €1.5 billion and the first and the second quarterly instalment of the 2023 dividend for €1.5 billion) as well as the buy-back of Eni shares (€1,837 million).

The Group Non-GAAP measure of its financial condition mostly tracked by management was leverage calculated by excluding the impact of IFRS 16 and was 0.20 at year end (0.13 at the end of 2022).

Capital expenditures by segment

Exploration & Production. In 2023, capital expenditures of the Exploration & Production segment amounted to €7,133 million, mainly related to the development of hydrocarbon fields (€6,293 million). Significant expenditures were directed mainly in Côte d'Ivoire, Congo, Egypt, Italy, the United Arab Emirates, Libya and Algeria. Exploration expenditures (€784 million) were directed in particular in Egypt, the United Arab Emirates, Mexico, Congo, Indonesia, Mozambique, Morocco, Cyprus, Lebanon, Oman, Tunisia and Algeria.

Global Gas & LNG Portfolio.

In 2023, capital expenditure in the Global Gas & LNG portfolio totaled €16 million.

Enilive, Refining and Chemicals. In 2023, capital expenditures in the Enilive, Refining and Chemicals segment amounted to €982 million and regarded mainly: (i) traditional and bio refining activity in Italy and outside Italy, biomethane activity (€621 million) for development initiatives, maintaining plants' integrity and stay-in-business, as well as HSE initiatives; (ii) marketing activity (€174 million) mainly for regulation compliance and stay-in-business initiatives in the retail network in Italy and in the rest of Europe.

Plenitude & Power. In 2023, capital expenditures in the Plenitude & Power segment amounted to €740 million and mainly related to development activities in the renewable business, acquisition of new customers as well as development of electric vehicles network infrastructure.

Recent developments and significant transactions

The table below sets forth certain indicators of the trading environment for the periods indicated:

	Three months ended March 31,	Three months ended March 31,
	2023	2024
Average price of Brent dated crude oil in U.S. dollars (1)	81.8	83.2
Average EUR/USD exchange rate (2)	1.072	1.086
Standard Eni Refining Margin (SERM) (3)	11.1	10.5
Gas at the TTF in \$/mmBTU	17.4	8.7

(1) Price per barrel. Source: Platt's Oilgram.

(2) Source: ECB.

(3) In \$/BBL, FOB Mediterranean Brent dated crude oil. Source: Eni calculations, as difference between the cost of a barrel of Brent crude oil and the value of the products obtained according to the standard yields of the Eni refining system, less expenses for industrial utilities.

In the period January 1 – March 31, 2024 the Brent crude oil price averaged 83 \$/BBL and was substantially in line with the first quarter 2023 and has been trending slightly above our expectations. The refining margins in the first quarter 2024, as measured by our benchmark SERM of about 10.5 \$/bbl have been trending slightly above our expectations for 2024 and was in line with the first quarter 2023. Natural gas spot prices at the European Title Transfer Facility have been averaging approximately 9 \$/mmBTU and are trending below both our assumptions for 2024 and compared to the first quarter 2023 and this could negatively affect our results of operations in the first quarter 2024 and beyond. Finally the euro vs the US dollar exchange rate in the first quarter 2024 averaged at 1EUR = 1.09 USD and was in line with both our expectations and the first quarter 2023.

See "management expectations of operations" below.

The main business transactions that occurred in the first quarter 2024 are reported in Item 4.

$$^{127}$$

MANAGEMENT'S EXPECTATIONS OF OPERATIONS

Business trends

Exploration & Production

In the next four-year plan 2024-2027, management is planning to increase the cash generation and returns in the E&P segment leveraging on profitable production growth, capital discipline, fast time-to-market of projects, and cost control. At the same time, we are planning to reduce CO2 direct emissions at our E&P operations. Our production plans and financial projections in the E&P segment are based on a flat Brent crude oil price scenario of 80 \$/BBL in the four-year plan 2024-2027 in nominal terms (i.e. taking into account management's own assumption on the inflationary rate going forward). The 2024 outlook features a small decline in crude oil prices (down by 4% from 2023) based on the assumptions of a balanced supplydemand environment and a "soft-landing" macroeconomic scenario and considering that global inventories are below recent year averages. Spot prices of natural gas are anticipated to continue the downward trend observed throughout 2023 due to an oversupplied market, with prices at the Title Transfer Facility "TTF", the main European hub, and at the Italian PSV forecast to decline by about 30% from 2023 down to 10 \$/mmBTU and then to partially recover in the subsequent years of our financial projections. Risks to that outlook include a more pronounced macroeconomic slowdown or a recession also due to tight monetary policies from central banks, a stronger USD dollar that could weaken growth in emerging economies and increase the cost of crude oil, continued production additions by US shale producers and other geographies (Brazil, Guyana, Canada) and the cohesion of the OPEC+ producer alliance in holding production discipline to support prices.

Post 2027, our Brent price assumptions in real terms (i.e. without taking into account inflation) are 68 \$/bbl till 2033, then declining to 48 \$ in 2050 to take into account our expectations of the energy transition impacts and a possible significant decline in demand for crude oil. Our long-term assumptions about the inflationary rate are about 2% per annum.

Due to those risks and uncertainties, management intends to retain a strong focus on capital and cost discipline, on shortening project cycles and on reducing the time-to-market of our reserves as levers to maintain our development projects profitable also at lower crude oil prices.

We plan to invest about €5.5-6 billion on average in the next four-year plan 2024-2027 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 Var Energi and Azule Energy. Those equity-accounted entities are expected to self-finance their respective capital expenditure needs, without requiring shareholder's funds. Furthermore, we expect to incur capital expenditures that will not be reported as part of the cash flow from investing activities in our future reporting periods since contractually deferred payment terms to suppliers will give rise to the recognition of finance payables.

We forecast hydrocarbons production (including our share of joint ventures and investees) to grow at a compounded average growth rate "CAGR" in a range of 3% - 4% in the four-year plan before portfolio activities. Including portfolio activities the CAGR is expected to be in the range of 2%, driven by organic developments, as well as the consolidation of the recently acquired assets of Neptune Energy, which is expected to add about 100 KBOE/d to our current production profile (also including our share of production of the associate Var Energi). Our production plans contemplate a gradual increase of the proportion of natural gas in the production mix till achieving a share higher than 60% by 2030 (including natural gas liquids).

Production growth in the four-year plan will be fueled by new fields start-ups and ramp-ups, mainly in Congo, Cote d'Ivoire, Libya, Indonesia, and Qatar.

We confirm our strategy designed to retain profitable and cash-generative E&P operation, leveraging successful exploration and effective development and field operation activities to accelerate the time-to-market of reserves and to reduce the full cycle cost of crude oil and hence the Brent breakeven price. The execution of an asset disposition plan will help bring forward the cash generation. Asset dispositions will target high-potential discoveries, where we retain large working interests and 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.

We believe that the designed strategy is warranted 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 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, 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 our industrial inputs (labor, materials, field services) are expected to rise driven by inflation, albeit at a smaller pace than in recent years. 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 we are planning to:

• performing project activities in accordance with a parallel approach rather than a sequential one, 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; examples of this approach are the Baleine project in Côte d'Ivoire where we have refurbished and upgraded an existing vessel thus reducing the timing of first oil and the Congo LNG project, which has started operations in just twelve months following the investment decision thanks to utilization of existing facilities and technologies;
• signing master agreements with our main supplies to maximize cost savings and by designing facilities using a modular approach that enables us to extend the useful lives of plants and vessels;
• reducing the time to complete tender processes to sign up contracts with EPC contractors and other key suppliers reducing the risk of future price revisions;
• leveraging near-field or infrastructure-led exploration that has proven to be successful at increasing the reserves at already producing fields thus enabling to exploit synergies from existing facilities; in recent years we made several discoveries of this type including the one in Côte d'Ivoire and others in Congo, Egypt, Algeria, and Mexico;
• 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 near-field discoveries recently made in Egypt and Algeria onshore will provide a rapid time-to-market due to those features. 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.

Phased project development and strict integration between exploration and development have improved overall project execution and cost efficiency. Finally, all our projects undergo a thorough HSE assessment leading to the definition of an integrated plan to reduce blow-out and other well and operational risks and costs.

According to our plans, exploration will continue ensuring cost-effective replacement of produced reserves, supporting cash generation and evolving our reserve portfolio towards the planned mix of resources featuring a bigger weight of natural gas going forward. Our exploration initiatives will comprise two clusters:

• Exploration projects in prospects near-field and in proven/mature areas and in other infrastructurelead 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 flows and production levels with minimum impact on expenditures;
• Selected initiatives in high-risk/high-reward plays, where we retain a large 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.

In the four-year plan 2024-2027, we will invest more than €1.5 billion in exploration activities.

Our production plans include assumptions relating to production levels in certain countries that are particularly exposed to risks of disruptions and political instability. 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, 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.

Global Gas & LNG Portfolio

We expect natural gas markets to remain oversupplied in 2024 and beyond due to massive production levels in the US coupled with new liquefaction capacity additions, a slow recovery of the Chinese economy, ramp-up of nuclear generation capacity, a slowdown in consumption in Europe driven by a weak industrial sector and energy savings, rising competition from renewables due to continued capacity additions, and finally good inventory levels because of a mild winter season in the Northern Hemisphere in 2024. This outlook will pressure natural gas prices. Against this backdrop, our GGP business will cope with an expected less favorable trading environment than in 2023 due to reduced margin opportunities in connection with anticipated lower pricing levels and reduced volatility. However, barring comparison with the significant performance of 2023 that was also supported by one-off gains in connection with contract renegotiations, management plans to retain sound profitability and cash generation in this business in the plan period.

Our planning assumptions are not factoring any purchases of natural gas from Russia, although our long-term supply contracts with Russia's state-owned company Gazprom are still valid. Our sales commitments relating to supplies to our retail subsidiary Plenitude, the supply of natural gas to our thermoelectric segment and ongoing sales contracts will be covered by purchases under non-Russia outstanding long-term contracts and by increasing off-takes of equity gas, 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 effectively manage our portfolio of assets (supply and sales contracts, their flexibilities and optionality and logistics availability) in order to extract value from portfolio flexibilities through continuing optimizations;
• (iii) To grow the LNG marketing business leveraging on the integration with the E&P segment with the aim of maximizing the profitability of equity natural gas along the entire value-chain. We plan to increase contracted supplies of LNG through new sources to achieve a robust portfolio of reselling opportunities, targeting a volume of contracted LNG of more than 18 MTPA by 2027.

We make use of commodity 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 are not accounted 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. However, in response to the increased liquidity risks, we have opted to reduce our risk management activities and that could make our results more volatile. Furthermore, we also make use of derivatives to improve margins by leveraging 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 derivatives are speculative in nature with gains and losses recognized through profit.

Refining

In 2023, the business of crude oil refining has delivered a satisfactory performance that was underpinned by strong crack spreads of gasoil driven by tight availability in Europe and by asset reliability. We believe that market imbalances tied to crude quality availability and products flows and other bottlenecks in the system will likely help refining margins in 2024, as well as an expected decline in natural gas prices. However, this business retains a cyclical nature, and we project refining margins to fall well below current levels in the medium term as new capacity is forecast to enter the market or achieve full ramp-up in the next years, in places like Nigeria, the Middle and Far East. Our forecasts are also modelling a gradual reduction in consumption of fossil fuels in our key European markets due to penetration of EV 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 natural gas consumption in the operations and the search of viable solutions to eventually restructure and downsize our oil-based, operated refineries in Italy. Consistent with this market view, we have launched a project to restructure another refinery in Italy (Livorno), which will follow the same reconfiguration process as the Gela and Venice hubs, and to transform it into a biorefinery with expected start up in 2026.

Enilive (biofuels & marketing)

Enilive, operational from January 1, 2023, is a new, 100 per cent-owned subsidiary of Eni, which has been established through the carve-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 will offer increasingly decarbonized solutions/products to people on the move, leveraging integration with its biorefineries as well as product and service innovation.

The Group plans to significantly grow the manufacturing capacity of biofuels with the goal of reaching more than 3 million tons of installed capacity in 2026 through the upgrading of existing plants, the planned entry into operations of another biorefinery in Italy and international expansion, building on the successful completion of a deal to establish a joint venture with a US refiner to jointly operate a biorefinery in Louisiana. In the plan period, we expect that other international opportunities will mature in South Korea in partnership with LG Chem and in Malaysia in partnership with Petronas and Euglena, where both initiatives will leverage our co-developed "Ecofining" technology to produce hydrotreated vegetable oils "HVO", with an expected start-up for both projects in 2026. Management is engaged in building a reliable and sustainable supply chain of bio-feedstock to be processed at the Company's manufacturing units. 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 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 under long-term agreements. In 2023, this agricultural business has supplied 4 Ktonnes of bio feedstock to our manufacturing plants in Italy. The agricultural business will be scaled up in the planning period to reach a level of supply in excess of 700 Ktonnes by 2027, covering more than 35% of our Italian biorefineries throughputs in Italy. This vertical integration will also boost margins on the production of biofuels, insulating our company from the volatility of raw materials. We are also planning to develop the offer of sustainable aviation fuels and of biomethane.

In marking 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 on new formats and partnerships with established operators in various fields.

Management believes that Enilive will significantly increase its profitability in the plan period, leveraging on the integration between biofuels production and marketing activities, and because of that it will gain better visibility on the marketplace. Based on those features, the management believes that Enilive can attract interest from external investors.

Chemicals business

In 2023, the chemicals sector managed by the subsidiary Versalis reported losses due to the long-term challenged fundamentals of the business, because of competition from producers in USA, Middle and East Asia, which are advantaged by plant scale and lower operating expenses, and a slowdown in demand for plastics, which exacerbated price competition. Furthermore, 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 four to five times that of the USA) and environmental obligations which made overseas products more competitive than ours, and those trends negatively affected products margins and sales volumes. Those negative trends are likely to continue affecting the business performance in 2024 and beyond. The Company is focused on executing an industrial plan intended to recover profitability by reducing exposure to the most commoditized market segments and to achieve a structurally more sustainable and competitive products mix. The main levers of the industrial plan comprise: (i) to develop the segment of bioplastics and biochemicals leveraging the integration of the recently-acquired Novamont; (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, (iii) to develop the business of the circular economy by increasing production of polymers made from the mechanical recycling of waste plastics; (iv) to improve integration and efficiency, balancing the cracking capacity with the internal needs for manufacturing polymers and lowering trade sales of intermediates which are exposed to the volatility of the cycle. A key driver of our strategy will be our proprietary technologies which can expand our presence in new markets, like for example the production of bio-ethanol from biomass, or the technology for producing polymers via the chemical recycling of used plastics that we are going to test by building a pilot plan at one of our industrial hubs in the plan period.

Plenitude

Plenitude, Eni's subsidiary managing the Group's legacy retail marketing of natural gas business, the renewable electricity business and the network of charging points for EV will leverage the synergies among those businesses to improve its profitability going forward. We plan to accelerate the development of the installed capacity to produce renewable power to reach over 8 GW of installed capacity by the end of the plan. Our network of charging points for electric vehicles will be expanded with the objective of reaching 40 thousand points by 2027. We plan to selectively grow our customer base, with the target to reach over 11 million customers by 2027 and to boost profitability by extracting more value from the customer portfolio, by supplying an increasing share of equity renewable energy and bio-methane, as well as by expanding the offer of new products and services other than the commodity and by 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. Based on those drivers, management expects that Plenitude will significantly improve its profitability going forward.

Expected Group financial performance

In 2024, the management expects to fund several large cash requirements. We expect to execute a largely committed capital budget of about €9 billion to fund the organic growth of the business. We will have disbursements in connection with the closing of the acquisition of the group Neptune Energy (€2 billion) and of assets in the segment of renewable generation in USA, which deal was announced at the end of 2023 and the closing occurred in early 2024. We expect to incur a one time cashout due to the payment of an Italian solidaristic tax contribution, provisioned in the financial statements (around €0.45 billion). Finally, we expect to return a substantial amount of cash to shareholders through dividends projected at €3 billion (which will include the third and fourth instalments of the dividend for fiscal year 2023 and the first two instalments of the 2024 dividend), as well as through the completion of the 2023 share repurchase program (€0.4 billion) and possibly the start of a new buy-back program.

Furthermore, our net borrowings will reflect the planned execution of reverse factoring transactions whereby the payables recognized in connection with the purchase of capital goods will be classified as finance debt due to the deferral of the payment terms agreed with the suppliers of such goods.

The Company expects to fund those cash requirements through a combination of cash generated from operations, the execution of a disposal plan and by taking on new finance debt. Those movements will likely result in an increased ratio of net borrowings (before IFRS 16 effects) to equity ("leverage"), although we expect that the Group leverage will remain very close to our stated long-term range of 0.15-0.25.

For 2024, we expect net cash provided by operating activities ("operating cash flow") to be the primary source of cash to fund our capital plans and returns to shareholders.

Our operating cash flow is mainly driven by our E&P business due to its relative 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 demand and supply and the worldwide levels of inventories, among others. Based on our experience, those backdrop conditions can vary very rapidly and accordingly hydrocarbons prices corrections can be sudden and severe. Due to those considerations, our operating cash flow features high variability and little predictability. The 2024 outlook is compounded by many risks and uncertainties in connection with trends in the global economy and the monetary policy of the US Federal Reserve which will greatly influence movements in currency markets and the economic performance of developing countries and that will have important consequences on a possible recovery of crude oil prices, and finally the unsteady recovery trajectory of the economy of China, which is a large consumer of crude oil. From an industrial standpoint the greatest uncertainties will involve the ability of US shale producers to continue growing production despite financial discipline, the performance of emerging growth areas like Brazil and Guyana, developments in the political relationships involving USA, Iran, and Venezuela and finally and above all the cohesion of the OPEC+ cartel in maintaining the production curbs and quota discipline to support prices. Considering those risks and uncertainties, we are assuming a Brent crude oil price of 80 \$/bbl for 2024, a couple of dollars lower than in 2023. We are also assuming a continuing downtrend in natural gas prices, which will reduce both E&P results and optimization opportunities of the portfolio of natural gas contracts managed by our GGP segment. As a result of those expected trends, our results of operations and cash flows for 2024 are expected to be lower than in 2023. We are assuming spot prices of natural gas at European hubs to be around 10 \$/mmBTU, the Company's gouge of the refining trading environment, SERM, at 8 \$/bbl and an average EUR vs USD exchange rate at 1EUR=1.08 USD.

In contrast to the volatility of our operating cash flows, our funding requirements to develop hydrocarbons reserves are characterized by a low degree of flexibility in the short term. 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-time projects due to the complexity of activities to be carried out before production is achieved and the pay-back period of capital projects may start. Once a final investment decision has been made to develop a new hydrocarbon field and contracts have been signed to build production facilities 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 expected compression of our cash flow from operations in 2024 due to reduced pricing and other assumptions will be occurring at a time when our funding needs to support our capital plans are forecast to remain at substantial levels. The planned €9 billion of capital expenditures for 2024 will be driven by new project start-ups and ramp-ups in E&P, cost inflation and by development of the renewable generation capacity of our subsidiary Plenitude and of other businesses linked to the energy transition. The businesses linked to the energy transition are currently absorbing cash because they are in a ramp-up phase.

Furthermore, we expect to fund a significant portion of the planned cash requirements in 2024 through the execution of an asset disposal plan which will encompass a possible dilution of our working interests at certain E&P assets (for example large discovery areas or fields currently in production phase), the divestment of non-strategic assets and the sale of minority interests in certain subsidiaries, which can attract the interest of institutional investors similar to the deal between our subsidiary Plenitude and EIP, whereby the external investor subscribed to a reserved share capital increase by contributing €0.6 billion of cash and assuming a 7.6% interest in the share capital of Plenitude. However, the execution of our disposal plan is exposed to risks in connection with an uncertain macro economic 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 adoption of a ceiling to the maximum amount of debt that the Company may incur. 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 project 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 the ability of the Company to fund the planned capital expenditures to grow and maintain the asset base through operating cash flow. For 2024 under our pricing, exchange rate and inflation assumptions, we expect to generate enough cash flow from operations to fund the planned capital expenditures of about €9 billion, leaving a surplus to cover other cash requirements.

To fund other Company cash commitments, including the cash disbursements in connection with already closed acquisitions, the payment of lease liabilities and of windfall taxes, as well as shareholders returns, we expect to use cash proceeds from our disposal plans and to take on new finance debt. Those plans are exposed to the volatility of hydrocarbons prices and refining margins. Brent prices have been trending slightly above our expectations so far in 2024, averaging 83.2 \$/bbl in the first quarter of 2024. Currently, we are estimating our operating cash flow to vary by approximately €130 million for each one-dollar change in the Brent crude oil price with respect to our base case assumption of 80 \$/bbl for 2024. Natural gas prices have been trending just below the Company's expectation, with the average spot price at the same date at around 9 \$/mmBTU; each one-dollar change in the sport prices of natural gas in Europe has almost the same impact as a one-dollar change in the Brent price (€130 million). The Company's refining margins have been performing better than expected, with an average of around 10.5 \$/bbl in this first quarter of 2024. Currently, we are estimating our cash flow operations to vary by about €120 million for each one-dollar change in the SERM.

For planning purposes, management assumed a USD/EUR exchange rate in the range of 1.08 – 1.12 U.S. dollars per euro in the 2024-2027 period. Given the sensitivity of Eni's results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty. In the first quarter of 2024 the USD/EUR exchange rate was line with our expectations. Currently, we are estimating our cash flow from operating activities to vary by about €540 million for a 5 USD/cent movement in the USD/EUR cross rate.

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, or short-term difficulties in accessing capital markets. At the end of 2023 this liquidity reserve amounted to €17.8 billion of cash on hand and held-for-trading securities and €9.1 billion of committed borrowings facilities.

Our 2024-2027 plan economics are assuming a Brent crude oil price flat at 80 \$/bbl and a spot price of natural gas at the main European hub at around 10-12 \$/mmBTU.

The actions planned in the next four-year period featuring profitable hydrocarbons production growth, an increasing contribution of our businesses linked to the energy transition managed by our subsidiaries Plenitude and Enilive, continuing portfolio optimizations in GGP, steady performance of the retail marketing of fuels, margin preservation in the oil refining business and a restructuring of the petrochemicals business managed by Versalis 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 will be in the position to boost shareholders returns and to retain a robust balance sheet with our core ratio of net borrowings to total equity – leverage – before the effects of IFRS 16 expected to fall back to the low end of the indicated range at the end of the plan period. Our financial plans are assuming an increased level of indebtedness at our subsidiary Plenitude, which is upgrading the generation capacity of renewable energy and electric vehicles infrastructure.

In the next four-year plan 2024-2027, we expect to incur about €35 billion of capital expenditures with the following breakdown for the main businesses:

• around €23 billion to develop new oil&gas projects, mainly natural gas and LNG initiatives, to maintain the production plateau at existing fields, and to explore for new hydrocarbons reserves, mainly in near-field prospects and mature areas (exploration will attract more than €1.5 billion of expenditures);
• around €5.4 billion to develop the renewable generation capacity, the network of EV charging points and other initiatives of Plenitude;
• around €0.9 billion to develop the ongoing initiatives in the businesses under development of upgrading depleted natural gas fields into hubs to permanently store CO2 and related facilities for transport and compression; those amounts will include construction of agricultural hubs to produce feedstock for Eni's biorefineries;
• around €3.4 billion to downstream activities, 50% dedicated to develop the manufacturing capacity of biofuels and upgrade the network of service stations and 50% to maintain plant reliability and safety in the businesses of oil refining;
• around €1.2 billion in the petrochemicals business.

We expect to fund part of the cash requirements of our capital expenditure programs through the execution of a disposal plan of €8 billion of net cash proceeds, i.e. in excess of the cash-outs related to the closing of the Neptune energy acquisition and other minor tuck-in acquisitions, over the next four years. By this way, we see our net cash used in investing activities to average around €7 billion per year in the plan period. Our disposal program will leverage on the possible divestitures of minority stakes in one or more of our subsidiaries engaged in the businesses of the energy transition and on the possible dilution of our working interests in some exploration assets and the sale of some producing fields in the E&P segment.

To support the Group cash generation, we are planning to execute a cost saving program of about €1.8 billion.

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 the oil prices. In the four-year plan 2024-2027 out of the planned capital budget of €35 billion, the portion allocated to uncommitted projects represents 10% in 2024, and an average of 50% in the subsequent 2025-2027 years.

Our financial projections and capital investment decisions are based on management's appreciation of the cost of capital to the Group at about 7%. This rate is in line with 2023 due to a perceived decrease of Eni's equity risk due to the restructuring executed throughout the downturn and an improved financial structured, which helped offset the increase in risk-free yields. 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).

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 growth in underlying earnings and cash flows at a constant scenario basis and the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders' remuneration, management also consider trends in the crude oil prices scenario and in other market variables.

As part of that framework and to reflect improved financial metrics of the Company, management is planning to enhance shareholders' remuneration by pegging expected distributions to a percentage ranging from 30 to 35% of the expected cash flow from operations before changes in working capital, up from the previous stated range of 25 to 30%. Distributions will contemplate a combination of dividends and share repurchases, with this latter representing the variable component of the planned remuneration policy. We expect to grow the dividend in future years in line with the expected growth in the Group underlying financial performance, and to improve the dividend resilience to the scenario.

In case the Group performs better than management's plans due for example to a better pricing environment than management expectations or better-than-expected business underlying performance, management intends to distribute up to 60% of the incremental cash flow from operations (up from the previous 35%). In case the scenario evolves contrary to management's expectations, the Company intends to preserve shareholders' returns leveraging on the Company's financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio.

For 2024, having assessed the progress of the Company in executing its strategy, basing on a sound financial position and a stable crude oil prices outlook, the management is planning to increase the annual total dividend to €1 per share, up 6% from €0.94 per share relating to fiscal year 2023. This dividend is expected to be paid in four equal quarterly instalments in September 2024, November 2024, March 2025 and May 2025. Therefore, the expected cash out for dividend payments in 2024 will include two instalments of the 2023 dividend of €0.23 and €0.24 per share respectively, and two instalments of the planned 2024 dividend of €0.25 per share each (for an overall cash outlay of €3 billion).

Furthermore, consistent with its remuneration policy, Eni plans to commence a new share buyback program of at least €1.1 billion, following due shareholders' approval at the Annual General Meeting scheduled in May 2024, which could increase to €3.5 billion. In the next four years, at the management's scenario, the Company expects to execute an overall buy-back plan of more than €6.5 billion, significantly reducing the share count.

Off-balance sheet arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, 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 described under "Contractual obligations" below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses.

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.

Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in "Item 18 – Note 28 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements".

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 and held-for-trading securities) of €17.8 billion and committed borrowing facilities of €9.1 billion for a total liquidity reserve of about €27 billion. This liquidity reserve according to management plans 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 adopting measures to strengthen its financial headroom to cope with possible market turbulence. 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 €35 billion of the four-year period 2024-2027 is allocated to uncommitted projects (15% in the first year, rising to 20% in the subsequent ones).

Working capital

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

Credit risk

In recent years, the Group has experienced a significant level of counterparty default due to Europe and Italy's weak economic growth and a downturn in crude oil prices affecting the solvency of national oil state-owned entities and local companies, which are joint operators in Eni-lead projects. The retail gas & power business managed by Plenitude is particularly exposed to the credit risk due to its large and diversified customer base, which includes thousands of medium and small-sized businesses and retail customers whose financial condition has been negatively and adversely affected by the economic slowdown and high energy costs owing to the natural gas crisis of 2022. Also, certain large industrial accounts at our wholesale natural gas business have been facing difficulties at paying amounts due to us. 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 new spike in the prices of energy commodities or 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 new restrictive measures in response to a resurgence of the pandemic or the war in Ukraine and Middle-East tensions lead to a double-dip in economic activity and energy demand, in the event of extended periods of constraints in the financial markets, 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 or share price.

Market risk

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

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

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

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

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

Research and development

For a description of Eni's research and development operations in 2023, see "Item 4 – Research and development".

Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

The following table lists the Company's Board of Directors as at December 31, 2023:

Name	Position	Year elected or appointed	Age
Giuseppe Zafarana	Chairman	2023	60
Claudio Descalzi	CEO	2014	68
Elisa Baroncini	Director	2023	57
Massimo Belcredi	Director	2023	62
Roberto Ciciani	Director	2023	51
Carolyn Adele Dittmeier	Director	2023	67
Federica Seganti	Director	2023	57
Cristina Sgubin	Director	2023	43
Raphael Louis L. Vermeir	Director	2020	68

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.

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 the 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.

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, and International Law on Sustainable Development 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.

She is 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), and a member of the University of the Associazione delle docenti universitarie dell'Università di Bologna (AdDU) Stering Committee. She participates in various associations and organisations 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. She is currently Coordinator of the Re-Globe Jean Monnet Module, Seed Funding Una Europa WHC@50 project, and Seed Funding Una Europa ImprovEUorGlobe project. Elisa Baroncini's fields of research include: the crisis of the WTO appellate body and the multilateral litigation 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.

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.

Massimo Belcredi was born in Brindisi in 1962 and has been Eni Director since May 2023. He is currently 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), of the teaching board of the Doctorate in Economics and Finance, and 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 Treasury 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 Directorates III, IV, V and VI of the Treasury 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, Chairman of the Audit Committee and member of the Corporate Governance, Sustainability and Nomination Committee of Alpha Services & Holdings SA and of its unlisted subsidiary Alpha Bank SA, where she is also responsible for supervising Environmental, Social and Governance issues as a member of the Corporate Governance, Sustainability and Nominations Committee.

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 is a member of the Audit Committee Leadership Network (ACLN), in which she actively participates in benchmark meetings between the Audit Committee Chairs of major European and North American companies and EcoDa. She is a statutory auditor, certified public accountant, certified internal auditor and certified risk management assurance professional. She is founder and leader of the working group dedicated to risk and control matters within the 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 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 has been teaching at the LUISS Guido Carli University, with teaching assignments in the fields of 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 and Chairman of BTX Italian Retail and Brands Srl, as well as Director of Finest SpA and BancoPosta Fondi SpA SGR (where she is Chairman of the Remuneration Committee and member of the Risk Committee).

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.

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.

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) and Vianini 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 practising as a lawyer for leading national and international law firms, then started a managerial career. As a lawyer, she has done consultancy work for 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 has written 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 on May 2023. He is currently an independent advisor for the mining and oil industry.

He serves as Trustee the Classical Opera Company in London, as well as Chairman of Malteser International and board member of Sedibelo Platinum Mines. 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 Masters of Science degrees in engineering and management from the Massachusetts Institute of Technology.

Senior Management

The table below sets forth the composition of Eni's Senior Management as at December 31, 2023. 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	CEO and General Manager of Eni	2014	42	68
Guido Brusco	Natural Resources Chief Operating Officer	2022	26	53
Francesco Gattei	Chief Financial Officer	2020	28	54
Giuseppe Ricci	Energy Evolutions Chief Operating Officer	2021	38	65
Gianfranco Cariola	Internal Audit Director	2021	12	55
Grazia Fimiani	Integrated Risk Management Director	2021	27	53
Luca Franceschini	Integrated Compliance Director and Board Secretary and Board Counsel	2016	32	57
Claudio Granata	Human Capital & Procurement Coordination Director	2020	40	63
Erika Mandraffino	External Communication Director	2020	17	51
Lapo Pistelli	Public Affairs Director	2020	8	59
Stefano Speroni	Legal Affairs & Commercial Negotiation Director	2020	5	61
Roberto Ulissi	Corporate Affairs and Governance Director	2006	17	61
Francesca Zarri	Technology, R&D & Digital Director	2020	27	54

The Chief Operating Officer Natural Resources, the Chief Operating Officer Energy Evolution, the Chief Financial Officer, the Director Legal Affairs and Commercial Negotiations, the Director Corporate Affairs and Governance, the Director Integrated Compliance, the Director External Communication, the Director Human Capital & Procurement Coordination, the Director Internal Audit, the Director Public Affairs, the Director Integrated Risk Management, the Director Technology, R&D & Digital, the Deputies of the Chief Operating Officers, the Director Upstream, the Director of Exploration, the Director Refining Evolution and Transformation, the Director CCUS, Forestry & Agro-Feedstock, the Director Power Generation & Marketing, the Head of Accounting and Financial Statements and the Head of Planning, Control and Insurance are members of the Management Committee⁹ , 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.

⁹ The committee includes also the Chairman of the Board and CEO's of certain Eni's subsidiaries

Senior Managers

Guido Brusco was born in Maratea (Potenza) in 1970. He graduated with Honors in Mechanical Engineering at "La Sapienza" University of Rome. He holds the position of Eni's Chief Operating Officer Natural Resources since February 2022. He joined Eni in 1997, starting his career in the technical areas of the Exploration & Production business holding positions of increasing seniority across different countries, up to the role of Operations Director in Egypt in 2005 and then in Kazakhstan in 2009. He took up the role of Managing Director in Kazakhstan in 2013 and subsequently Managing Director in Angola in 2015. Most recently he held the positions of Executive Vice President for the Sub-Saharan Africa Region and then Director of Eni's Upstream division. In the current position as Chief Operating Officer Natural Resources, he oversees Eni's global oil & gas exploration, development and production activities, gas and LNG portfolio, sustainable development, CCUS, forestry and agri-feedstock. Since December 2021, he is board director of Vår Energi, a company listed on the Oslo Stock Exchange. He has been appointed Chairman of Confindustria Energia, Italy's Federation of energy sector associations, in July 2023.

Francesco Gattei was born in Bologna in February 1969. He was appointed Chief Financial Officer in Eni on August 1, 2020. 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 United States, Mexico, Venezuela and Argentina. He was a member of the Board of Directors of Saipem from 2014 to 2015. He graduated in Economics and Commerce at the University of Bologna with a thesis on the oil market. He obtained the MEDEA (Master in Energy and Environmental Management) Master's from the Scuola Mattei in 1994.

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 as where he was responsible for Refining Processes Development and oversaw the performance optimisation 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 made 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 12 September 2016 he was appointed as Chief Refining & Marketing Officer and, 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 has been appointed President of Confindustria Energia and since 2018 President of AIDIC (Italian Association of chemical Engineering).

Gianfranco Cariola was born in Cosenza in 1968, he was appointed as Director Internal Audit at Eni on 1st April 2021. He is currently member of the FAO Oversight Advisory Committee (the United Nations Food and Agriculture Organization). 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.

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 was appointed Director Human Capital & Procurement Coordination in Eni on July 1, 2020. He has been 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 organization 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 has been 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 graduated in Economics.

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).

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 of listed companies.

Francesca Zarri was born in 1969 in Bologna. She was appointed Director of Technology, R&D & Digital of Eni on July 1, 2020. In 1997, she joined Agip S.p.A to work in the Reservoir Department as reservoir modeler and petroleum engineer and in 2000, she worked on Eni operated assets in Scotland (North Sea). In 2004, after moving to the Engineering and Projects Department, she became the head of the Adriatic Off-shore Projects department, based in Ravenna District. In 2006, she was back to work on in-field production monitoring and optimization as the Head of the Production Optimization Technology Department, which at that time, also included most of the Eni's Laboratories in Bolgiano. From 2007 to 2010, she worked for West Africa as Project and Development Director of Eni Congo, completing new and demanding project activities in the country (oil, gas and power). In 2011, she further expanded her experience by diversifying in the procurement function where she became the Head of American Region then the Head of Procurement Services, as well as the Professional Family. During the same period she was Eni's representative for Commercial Committee in the South Stream Project. In 2013, she was back to follow the development of upstream projects as the Vice President for West Africa Projects Monitoring and Technical Coordination and later in Eni Congo as Development Projects Director, where she also became the President of Enrico Mattei School in Pointe Noire. In 2017, she was called to join the role of Head of the Italian Southern District until november 2019, when she was appointed as Senior Vice President Italian Activites Coordination. Since April 2020, she is the President of Eniservizi, the President and CEO of SPI and the Eni representative in Assomineraria. Since 2014, she has been the member of boards of directors of several Eni subsidiaries in Italy and abroad. She earned MS degree in Mining Engineering (100/100) from the University of Bologna; she also attended, in 1995, the Eni Master MEDEA (Master in Energy and Environmental Management) with Economics specialization.

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, 2023, 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 2023 period, filled said roles, even if only for a fraction of the year), was €1,168 thousand.

Name		(€ thousand)
Descalzi Claudio	Chief Executive Officer	428
Brusco Guido	Chief Operating Officer Natural Resources	6
Ricci Giuseppe	Chief Operating Officer Energy Evolution	90
Senior managers (a)		644
		1,168

(a) No. 23 managers.

Boardpractices¹⁰

Corporate Governance

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.

Board 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 nonoperational 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 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:

¹⁰ The information contained in this chapter is updated to December 31, 2023 and for specific aspects, expressly indicated, up to the date of approval of this Report.

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 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. Determines their duties, and also upon proposal of the Remuneration Committee and following consultation with the Board of Statutory Auditors, the compensation of the relevant members; acting upon proposal of the same committees, approves their rules of procedures and annual budgets. Moreover, establishes in the rules of procedure of the committees 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 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.

• 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 four-year 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 with the support of the Control and Risk Committee, it annually defines, within the framework of the four-year Plan, the specific guidelines for the internal control and risk management system, in line with the Company's strategies, and evaluates their implementation annually, based on a report from the Chief Executive Officer, without prejudice to the general guidelines on the subject contained in internal regulations. 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 fouryear 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.

• 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 consolidated non- financial statement, the consolidated annual Sustainability Report not already contained within the non-financial statement and the half-year financial report. It also examines and approves any semi-annual and 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, at least on a semi-annual basis, a report on their activities.
• 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 jointcontrol 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 the provisions of point 26, 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 (with the exception, for all of these, of transactions with and between subsidiaries), mergers, demergers and liquidations of companies exceeding €200 million in the upstream oil&gas sector and €150 million in other business sectors, without prejudice to art. 23.2 of the 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;

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 whollyowned 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 noncontrolled 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); (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.

• 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.
• With the support of the Control and Risk Committee, determines 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) 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.

• 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.

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 assessment carried out in February 2023, 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.

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.

Board 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. 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 meetings¹¹as 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.

¹¹ 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."

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.

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.
• h) reports to the Board, at least once every six months and no later than the deadline for the approval of the annual and semi- annual financial report, on its activities at the Board meeting indicated by the Chairman of the Board of Directors.

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.¹²

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) ¹³. 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;

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;

¹² 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.

¹³The 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.

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 nonfinancial 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).

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:

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;

k) reports to the Board of Directors, at least once every six months and no later than the deadline for the approval of the annual and semi-annual financial report, on the activity carried out, at the Board meeting indicated by the Chairman of the Board of Directors.

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.

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.

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. at least once every six months, reports to the Board of Directors on its activities, by the date of the approval of the annual and semi-annual financial reports, during the meeting of the Board of Directors indicated by the Chairman of the Board of Directors;

m. 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.

Board of Statutory Auditors

		Year first appointed to Board of
Name	Position	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 lists are presented by shareholders representing at least 0.5% of the 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 2020 which Eni adopted from December 23, 2020, applicable from January 1, 2021, 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.

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 transmits to the Board the "additional report" of the audit firm adding proper evaluation if deemed necessary; b) oversees the financial reporting process and 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, without violating its independence; d) oversees the statutory audit of annual accounts and consolidated accounts, 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 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" 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 department 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.

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 highranking 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 November 18, 2021 approved the updating of Model 231.

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 Auditors¹⁴, 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.

Employees

As of December 31, 2023, Eni had a total of 33,142 employees, with an increase of 954 employees (3% compared to December 31, 2022), which mainly reflects an increase of 871 employees working in Italy and 83 employees working abroad.

This growth is mainly due to the extraordinary M&A operations, in particular the acquisition of the Novamont group (including the consolidation of Matrica SpA), world leader in the production of bioplastics and the development of biochemicals and bioproducts through the integration of chemistry, environment and agriculture.

	2023	2022	2021
		(number)
Exploration & Production	8,785	8,689	9,409
Global Gas & LNG Portfolio	669	870	847
Enilive, Refining and Chemicals	14,092	13,132	13,072
Plenitude & Power	3,018	2,794	2,464
Corporate and Other activities	6,578	6,703	6,897
	33,142	32,188	32,689

The table below sets forth Eni's employees as of December 31, 2021, 2022 and 2023 in Italy and outside Italy:

	2023	2022	2021
		(number)
Italy	3,193	3,192	3,364
Outside Italy	5,592	5,497	6,045
	8,785	8,689	9,409
			276
Outside Italy	390	588	571
	669	870	847
			9,028
			4,044
	14,092	13,132	13,072
Italy	2,230	2,096	1,864
Outside Italy	788	698	600
			2,464
			6,503
			394
	6,578	6,703	6,897
			21,035
Outside Italy	11,393	11,310	11,654
	33,142	32,188	32,689
	960	966	986
	Italy Italy Outside Italy Italy Outside Italy Italy	279 9,835 4,257 3,018 6,212 366 21,749	282 8,986 4,146 2,794 6,322 381 20,878

¹⁴ Until December 31, 2023, the Magistrate of the Court of Auditors was Manuela Arrigucci.

We seek to maintain constructive relationship with labor unions.

Share ownership

As of February 27, 2024, the cumulative number of shares owned by Eni's Directors, Statutory Auditors and Senior Managers was 1,076,467 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	426,272
Senior Managers		659,195(a)

(a) No. 10,141 shares owned by spouses not legally separated and by underage children.

Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY 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 25, 2024, 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%¹⁵ pursuant to Article 120 of the Legislative Decree No. 58/1998 and to the Consob Regulation No. 11971/1999 was:

Title of class	Number of shares owned	Percent of class
Ministry of Economy and Finance	157,552,137	4.797
Cassa Depositi e Prestiti SpA	936,179,478	28.503

As of March 25, 2024, the percentage of Eni's treasury shares was equal to 2.75% of the share capital 16 .

In relation to the Italian legislation governing the special powers of the Italian State see "Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)".

As of March 25, 2024, there were 23,886,023 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 1.45% 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 companies¹⁷ .

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".

¹⁷For more details on internal rules on related parties transactions, please refer to Item 10, paragraph "Interests in Company's transactions".

¹⁵Major 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.

¹⁶Eni's Board of Directors approved the start of the buy-back program for 2023 in execution of the authorization granted by the Shareholders Meeting held on May 10, 2023. Purchases started on May 12, 2023 and terminated on March 5, 2024. Following the purchases made until the termination of the buy-back programme for the year 2023, considering the treasury shares already held and the assignment of ordinary shares to Eni's directors, following the conclusion of the Vesting Period as provided by the "Long-Term Incentive Plan 2020-2022" approved by Shareholders' Meeting of May 13, 2020, Eni held n. 181,664,440 shares equal to 5.38% of the share capital. Following the cancellation of no. 91,447,368 treasury shares made on the basis of the authorization granted by the Shareholders' Meeting held on May 10, 2023 and executed on March 25, 2024, Eni holds no. 90,221,072 treasury shares.

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 the existing risk provisions disclosed in " Item 18 - Note 21 to the Consolidated Financial Statements – Provisions", and that in some instances it is not possible to make a reliable estimate of 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 a negative outcome to be 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 growth in underlying earnings and cash flows at a constant scenario basis and the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders' remuneration, management also consider trends in the crude oil prices scenario and in other market variables.

As part of that framework and to reflect improved financial metrics of the Company, management is planning to enhance shareholders' remuneration by pegging expected distributions to a percentage ranging from 30 to 35% of the expected cash flow from operations before working capital, up from the previous stated range of 25 to 30%. Distributions will contemplate a combination of dividends and share repurchases, with this latter representing the variable component of the planned remuneration policy. We expect to grow the dividend in future years in line with the expected growth in the Group underlying financial performance, and to improve the dividend resilience to the scenario.

The management intend to distribute up to 60% of the incremental cash flow from operations due to better-than-expected Group financial results (up from the previous 35%). In case the scenario evolves contrary to management's expectations, the Company intends to preserve shareholders' returns leveraging on the Company's financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio.

For 2024, having assessed the progress of the Company in executing its strategy, basing on a sound financial position and a stable crude oil prices outlook, the management is planning to increase the annual total dividend to €1 per share, up 6% from €0.94 per share relating to fiscal year 2023. This dividend is expected to be paid in four equal quarterly instalments in September 2024, November 2024, March 2025 and May 2025. Therefore, the expected cash out for dividend payments in 2024 will include two instalments of the 2023 dividend of €0.23 per share each, and two instalments of the planned 2024 dividend of €0.25 per share each.

Furthermore, consistently with its remuneration policy and as the current authorized buy-back program has been completed in March 2024, Eni plans to commence a new share buyback program of at least €1.1 billion, following expected shareholders' approval at the Annual General Meeting scheduled in May 2024, which could rise up to €3.5 in case of betterthan-expected results. In the next four years, at the management's scenario, the Company expects to execute an overall buyback plan of more than €6.5 billion, significantly reducing the share count.

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 date.

Item 9. THE OFFER AND THE LISTING

Offer and listing details

The principal trading market for the ordinary shares of the Company, without indication of par value (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.

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 25, 2024, there were 23,886,023 ADRs outstanding, representing 47,772,046 ordinary shares or approximately 1.45% of all Eni's shares outstanding, held by 109 holders of record (including the Depository Trust Company) in the United States, 108 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. 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 constituents of the FTSE MIB are selected based on market capitalization of free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free float and foreign ownership limits. FTSE MIB is the principal indicator used to track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market ("IDEM") managed by Borsa Italiana. The Shares are a component of the FTSE MIB, with a weighting of approximately 6.2%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective March 11, 2024.

A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on EXM, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the multilateral trading facility of securitised derivatives financial instruments, organised and managed by Borsa Italiana ("SeDeX"). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic multilateral trading facility where it is possible to trade securitized derivatives (for instance, covered warrants and certificates).

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an "official price", calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades, and a "reference price", calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on EXM, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective March 25, 2024: (i) ± 5.0% (or such other amount established by Borsa Italiana in the "Guide to the Parameters" for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price being the previous day's reference price, in the opening auction or the price at which contracts are concluded in the auction phase after each auction phase; if no auction price is determined, the static price is equal to the price of the first contract concluded in the continuous trading phase); and (ii) ± 3.0% (or such other amount established by Borsa Italiana in the "Guide to the Parameters") with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.

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.

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. In particular, on May 10, 2023, the Shareholders' Meeting approved an amendment to the By-laws regarding the cancellation of 195,550,084 treasury shares with no par value leaving the amount of the share capital unchanged. Moreover, on the same date, the Shareholder's Meeting authorised 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 275,000,000 treasury shares purchased on the basis of the authorisation of the same Shareholders' Meeting. The cancellation of no. 91,447,368 treasury shares made on the basis of the above mentioned authorization was executed on March 25, 2024, See "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".

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, 2011¹⁸ 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 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 Chairwoman 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 2024, see the Remuneration Report 2023 incorporated herein by reference).

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.

¹⁸These 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.

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 3,284,490,525¹⁹ ordinary registered shares without indication of par value as of March 25, 2024. 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 both 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 31, 2024, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization), or by the Board of Directors. 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.

¹⁹The Shareholders' Meeting, held on May 10, 2023, (i) has approved the proposal of cancellation of 195,550,084 treasury shares, without any impact on the Company's share capital and (ii) has approved 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 275,000,000 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 91,447,368 treasury shares made on the basis of the above mentioned authorisation was executed on March 25, 2024.

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.

In accordance with 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 containing "Measures to strengthen the National Health Service and provide economic support for families, workers and businesses connected with the COVID-19 epidemiological emergency", and of Decree Law no. 198/2022, ratified with amendments by Law no. 14/2023, that extended the effectiveness of the abovementioned measures also to the Shareholders' Meeting to be held by July 31, 2023, the participation in the Shareholders' Meeting of May 10, 2023 was permitted solely through the Shareholders' representative designated by the Company pursuant to Article 135-undecies of Consolidated Law on Financial IntermediationLaw no 21 of March 5, 2024 extended the effectiveness of the above-mentioned measures also to the Shareholders' Meeting to be held by December 31, 2024.

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 3²⁰ 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 to company assets in the following sectors: defense and national security; broadband electronic telecommunication networks based on 5G technology, cloud-based and other assets relevant to cybersecurity; energy, transport and communications, as defined by the regulations which implement the relevant law.

With reference to the energy sector, 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, 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; there is also an obligation to notify acquisitions that 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 security or public order.

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%.

²⁰This 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.

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 nonfinancial 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 entail 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.

Finally, 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 Intermediation²¹ and the Consob Regulation²², any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%²³, 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.

²¹Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.

²²Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.

²³If 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.

For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria²⁴ . 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 investments²⁵ .

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 months²⁶. 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 noncompliance, 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.

²⁴Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.

²⁵Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.

²⁶Consob 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.

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 Authority²⁷ 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 preemptive 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.

²⁷Autorità garante della concorrenza e del mercato (AGCM).

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 are (i) resident in an EU Member State or EEA State included in the White List, and (ii) subject to a corporate income tax in their country of residence.

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.

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 2023, 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.

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 the capital gains tax.

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. The tax rate applicable is 0.10% 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 if 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.

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-tomarket, 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, (the "Code"), 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 dividendsreceived 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.

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).

Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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 subsidiaries Eni Finance International (merged into Eni SpA in December 2023) and 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 and Eni Finance International (merged into Eni SpA in December 2023) manage the Group subsidiaries' financing requirements in Italy, outside Italy and in the United States, respectively, 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 (socalled 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.

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.

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 applicable.

Item 12B. Warrants and rights

Not applicable.

Item 12C. Other securities

Not applicable.

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 agentfor 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.

The following ADS fees are payable 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 by 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 2023, the Depositary reimbursed to Eni \$ 2,553,685.49 in connection with the above mentioned expenditures.

The Depositary has also agreed to waive certain standard fees associated with the administration of the ADR Program.

PART 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

Disclosure controls and procedures

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.

Management's Annual Report on Internal Control over Financial Reporting

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 31 entities from its assessment of internal control over financial reporting as of December 31, 2023 because they were acquired by the Company in several purchase business combinations during 2023. 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 2% of consolidated total assets and less than 1% of consolidated total revenues as of and for the year ended December 31, 2023.

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, 2023.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2023, 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.

Changes in Internal Control over Financial Reporting

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. [RESERVED]

Item 16A. Boardof Statutory Auditors financial expert

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 16B. 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 16C. Principal accountant fees and services

PricewaterhouseCoopers SpA (PwC SpA) served as Eni's principal independent registered public accounting firm for fiscal year 2023, 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, 2023 and 2022.

		Year ended December 31,
	2023	2022
		(€ thousand)
Audit fees	26,562	24,355
Audit-related fees(a)	3,000	2,834
Tax fees	-	11
All other fees	-	-
Total	29,562	27,200

(a) Audit related services provided by PwC SpA mainly relate to services for the issue of comfort letters, services related to the report prepared by Eni SpA on payments to governments and checks on cost recharges/rates, agreed verification procedures, and tariff certifications.

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.

<-- PDF CHUNK SEPARATOR -->

Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning.

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.

Pre-approval policies and procedures of the Internal Control 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 preapproved. 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 2023, 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 16D. Exemptions from the Listing Standards for Audit 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. Purchases of equity securities by the issuer and affiliated purchasers

Eni's Board of Directors, in execution of the authorization granted by the Eni Shareholders' Meeting of May 10, 2023 executed share buy-back program of the Eni's common shares amounting to €2.2 billion, repurchasing about 153 million of shares. The purchases started on May 12, 2023 and ended on March 5, 2024.

190

Period	Total number of shares purchased	Average weighted price paid per share € per share	Total number of shares purchased as part of publicly announced plans or programs	Total purchase cost (€ million)	Approximate € value of Shares that may yet be purchased under the plans or programs (€ million)
Start of the program May 12 - May 31,2023	7,898,757	13.11	7,898,757	104	2,096
1 June - 30 June	25,716,677	12.95	25,716,677	333	1,763
1 July - 31 July	15,512,330	13.47	15,512,330	209	1,554
1 August - 24 August	12,872,236	13.94	12,872,236	179	1,375
4 September - 30 September	14,109,617	15.08	14,109,617	213	1,162
1 October - 31 October	18,728,330	15.25	18,728,330	285	877
1 November - 29 November	17,543,460	15.14	17,543,460	266	611
1 Dicember - 31 Dicember	16,512,857	15.02	16,512,857	248	363
1 January - 31 January	14,686,415	15.06	14,686,415	221	142
1 February - 29 February	8,739,490	14.39	8,739,490	126	16
1 March - 5 March	1,127,199	14.35	1,127,199	16	0
Total as of March 5, 2024	153,447,368	14.34	153,447,368	2,200

The management will request the Annual Shareholders' Meeting convened in May 2024 to grant authorization to execute a new buy-back program.

Item 16F. Change in Registrant's Certifying Accountant

Not Applicable

Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the NewYork Stock Exchange Listed Company 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").

191

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 threeyear "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 in the same group of the issuer that could influence the independence of judgment.

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-executive Directors

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 2023, the independent Directors, coordinated by the Lead Independent Director, met on March 16 and on October 26 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.

Audit Committee

NYSE standards. 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.

Eni standards. 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/Corporate Governance 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.

Remuneration 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 an 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 November 18, 2021, taking into account the experience gained, amendments to Legislative Decree no. 231/2001, and the corporate organizational changes of Eni SpA.

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 disclosure

Not applicable since Eni does not engage in mining operations.

Item 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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 leverages 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 annual 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 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.

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 repairing expenses;
• Interruption in the IT systems used by the finance department which may lead to a temporarily inability to collect receipts which may results in loss of 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 infrastructures, availability of services for cybersecurity defense, the 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.

Those measures are intended to defend the Company from unauthorized access to its information systems, and from breaches or disruption of its industrial control systems as well as to prevent and contain potential impacts deriving from cyberattacks.

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 cyber threats that could interfere with information systems working properly 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 also 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 the majority of the Company's data is 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, by preserving continuity at the core business and corporate applications. 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;
• iii) reinforcement of the geographic connectivity of the green data center with the Company's intranet access to the web and services from 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.

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 businesssupport 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.

196

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 threats, 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 of IT, 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-today 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 discose 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. 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.

Item 17. FINANCIAL STATEMENTS

NOT APPLICABLE

Item 18. FINANCIAL STATEMENTS

Indexto Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm (PCAOB ID:00030)	F-1
Consolidated Balance Sheet as of December 31, 2023 and December 31, 2022	F-4
Consolidated Profit and Loss Account for the years ended December 31, 2023, 2022 and 2021	F-5
Consolidated Statement of Comprehensive Income for the years ended December 31, 2023, 2022 and 2021	F-6
Consolidated Statement of Changes in Equity for the years ended December 31, 2023, 2022 and 2021	F-7
Consolidated Statement of Cash Flows for the years ended December 31, 2023, 2022 and 2021	F-10
Notes on Consolidated Financial Statements	F-12

198

Item 19. EXHIBITS

• 1. By-laws of Eni SpA
• 1. Description of securities registered under Section 12 of the Exchange Act
• 1. List of subsidiaries (see Item 18 Note 37 Other information about investments of the Notes on Consolidated Financial Statements)
• 1. Code of Ethics (incorporated by reference to Exhibit 11 to Form 20-F 2019 (File No. 001-14090) filed on April 2, 2020)
• 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 remuneration report prepared in accordance with Italian listing standards for the year 2023 incorporated herein by reference
• 15.a(ii) Report of Ryder Scott Co
• 15.a(iii) Report of Sproule
• 15.a(iv) Report of DeGolyer and MacNaughton
• 15.a(v) Report of DeGolyer and MacNaughton
• 97 Executive Compensation Clawback policy
• 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
• 1. Cover Page Interactive Date File (formatted as Inline XBRL and contained in Exhibit 101)

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: April 5, 2024

Eni SpA

/s/FRANCESCO ESPOSITO

Francesco Esposito Title: Head of Accounting and Financial Statements

200

Table of Contents 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 sheets of Eni SpA and its subsidiaries (the "Company") as of December 31, 2023 and 2022, 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, 2023, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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 31 entities from its assessment of internal control over financial reporting as of December 31, 2023 because they were acquired by the Company in several purchase business combinations during 2023. We have also excluded these 31 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 2% and 1% of consolidated total assets and consolidated total revenues, respectively, as of and for the year ended December 31, 2023.

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.

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 Property, Plant and Equipment, Net

As described in Notes 1 and 12 to the consolidated financial statements, the Company's consolidated net carrying amount for property, plant and equipment was €56.3 billion as of December 31, 2023, of which €48.7 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 €5.7 billion for the year ended December 31, 2023. 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, proved oil and gas assets are depreciated generally on a unit of production basis. Proved exploration rights and acquired proved mineral interests are amortised over proved reserves; proved exploration and appraisal costs and development costs are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves. The accuracy of reserve estimates depends on a number of factors, assumptions and variables, including: (i) the quality of available geological, technical and economic 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 estimates which may drive substantial upward or downward revisions; 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 and costs existing as of the date when these estimates are made. 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 property, plant and equipment, 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, including future rates of production, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the 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, including future rates of production and the assumptions applied to the data related to operating costs and development costs.

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 reserves, including future rates of production. As a basis for using this work, we obtained an understanding of the qualifications of management's specialists' and assessed the Company's relationship with the specialists. The procedures performed also included evaluating the methods and assumptions used by management's specialists, testing the data used by the specialists, and evaluating the specialists' findings. These procedures also included, among others, testing the completeness and accuracy of the data related to operating costs and development costs. Additionally, these procedures included evaluating whether the assumptions applied to the data related to operating costs and development costs were reasonable as compared to the past performance of the Company.

Recoverability Assessment of E&P Property, Plant and Equipment, Net – Proved Oil and Natural Gas Properties

As described in Notes 1, 12 and 15 to the consolidated financial statements, the Company's consolidated net carrying amount for property, plant and equipment was €56.3 billion as of December 31, 2023, of which €48.7 billion relates to the E&P segment. The Company incurred impairment losses, net of recognized impairment reversals, before taxes associated with oil and natural gas properties in the E&P segment of €1.0 billion for the year ended December 31, 2023. The recoverability of non-financial assets is assessed whenever events or changes in circumstances indicate that carrying amounts of the assets may not be recoverable. 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 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 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. 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, market demand 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.

The principal considerations for our determination that performing procedures relating to the recoverability assessment of E&P property, plant and equipment, net – proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the value in use of proved oil and natural gas properties, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management's significant assumptions, including future rates of production, future commodity prices, operating costs, and development costs, 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 recoverability assessments of proved oil and natural gas properties. These procedures also included, among others (i) testing management's process for developing the value in use of proved oil and natural gas properties; (ii) evaluating the appropriateness of the value in use model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future rates of production, commodity prices, and operating costs and development costs. Evaluating the reasonableness of management's assumptions related to future commodity prices involved comparing the prices against observable market data. Evaluating operating costs and development costs involved evaluating the reasonableness of management's assumptions as compared to the past performance of the Company. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company's future commodity prices and the appropriateness of the value in use model. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the future rates of production as stated in the Critical Audit Matter titled "The Impact of Estimated Proved Oil and Natural Gas Reserves on Property, Plant and Equipment, Net". As a basis for using this work, we obtained an understanding of the qualifications of management's specialists and assessed the Company's relationship with the specialists. The procedures performed also included evaluating the methods and assumptions used by management's specialists, testing the data used by the specialists, and evaluating the specialists' findings.

/s/ PricewaterhouseCoopers SpA Rome, Italy April 5, 2024

We have served as the Company's auditor since 2019.

CONSOLIDATED BALANCE SHEET (€ million)

		December 31, 2023			December 31, 2022
	Note	Total amount	of which with related parties	Total amount	of which with related parties
ASSETS
Current assets
Cash and cash equivalents	(6)	10,193	3	10,155	10
Financial assets at fair value through profit or loss	(7)	6,782		8,251
Other current financial assets	(17)	896	19	1,504	16
Trade and other receivables	(8)	16,551	1,363	20,840	2,427
Inventories	(9)	6,186		7,709
Income tax receivables	(10)	460		317
Other current assets	(11) (24)	5,637	32	12,821	341
		46,705		61,597
Non-current assets
Property, plant and equipment	(12)	56,299		56,332
Right-of-use assets	(13)	4,834		4,446
Intangible assets	(14)	6,379		5,525
Inventory - Compulsory stock	(9)	1,576		1,786
Equity-accounted investments	(16) (37)	12,630		12,092
Other investments	(16)	1,256		1,202
Other non-current financial assets	(17)	2,301	1,840	1,967	1,631
Deferred tax assets	(23)	4,482		4,569
Income tax receivables	(10)	142		114
Other non-current assets	(11) (24)	3,393	168	2,236	26
		93,292		90,269
Assets held for sale	(25)	2,609		264
TOTAL ASSETS		142,606		152,130
LIABILITIES AND EQUITY
Current liabilities
Short-term debt	(19)	4,092	222	4,446	307
Current portion of long-term debt	(19)	2,921	21	3,097	36
Current portion of long-term lease liabilities Trade and other payables	(13) (18)	1,128 20,654	21 4,245	884 25,709	35 3,203
Income tax payables	(10)	1,685		2,108
Other current liabilities	(11) (24)	5,579	62	12,473	232
		36,059		48,717
Non-current liabilities
Long-term debt	(19)	21,716	65	19,374	26
Long-term lease liabilities	(13)	4,208	6	4,067	28
Provisions	(21)	15,533		15,267
Provisions for employee benefits	(22)	748		786
Deferred tax liabilities	(23)	4,702		5,094
Income tax payables	(10)	38		253
Other non-current liabilities	(11) (24)	4,096	511	3,234	462
		51,041		48,075
Liabilities directly associated with assets held
for sale	(25)	1,862		108
TOTAL LIABILITIES		88,962		96,900
Share capital		4,005		4,005
Retained earnings		32,988		23,455
Cumulative currency translation differences		5,238		7,564
Other reserves and equity instruments		8,515		8,785
Treasury shares		(2,333)		(2,937)
Profit		4,771		13,887
Equity attributable to equity holders of Eni		53,184		54,759
Non-controlling interest		460		471
TOTAL EQUITY	(26)	53,644		55,230
TOTAL LIABILITIES AND EQUITY		142,606		152,130

See the accompanying notes.

Information about the definitive purchase price allocation of business combinations made in 2022 is provided in note 27 ‐ Other Information.

CONSOLIDATED PROFIT AND LOSS ACCOUNT (€ million except as otherwise stated)

		2023			2022	2021
	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		93,717	4,322	132,512	10,872	76,575	3,000
Other income and revenues		1,099	156	1,175	156	1,196	52
REVENUES AND OTHER INCOME	(29)	94,816		133,687		77,771
Purchases, services and other	(30)	(73,836)	(15,885)	(102,529)	(15,327)	(55,549)	(8,644)
Net (impairments) reversals of trade and other receivables	(8)	(249)	5	47	(2)	(279)	(6)
Payroll and related costs	(30)	(3,136)	(8)	(3,015)	(18)	(2,888)	(21)
Other operating income (expense)	(24)	478	17	(1,736)	3,306	903	735
Depreciation and amortization	(12) (13) (14)	(7,479)		(7,205)		(7,063)
Net (impairments) reversals of tangible, intangible and right-of-use assets	(15)	(1,802)		(1,140)		(167)
Write-off of tangible and intangible assets	(12) (14)	(535)		(599)		(387)
OPERATING PROFIT (LOSS)		8,257		17,510		12,341
Finance income	(31)	7,417	155	8,450	160	3,723	79
Finance expense	(31)	(8,113)	(28)	(9,333)	(164)	(4,216)	(46)
Net finance income (expense) from financial assets at fair value through profit or loss	(31)	284		(55)		11
Derivative financial instruments	(24) (31)	(61)	1	13	2	(306)
FINANCE INCOME (EXPENSE)		(473)		(925)		(788)
Share of profit (loss) from equity-accounted
investments		1,336		1,841		(1,091)
Other gain (loss) from investments		1,108	445	3,623	30	223
INCOME (EXPENSE) FROM INVESTMENTS	(16) (32)	2,444		5,464		(868)
PROFIT (LOSS) BEFORE INCOME TAXES		10,228		22,049		10,685
Income taxes	(33)	(5,368)		(8,088)		(4,845)
PROFIT (LOSS)		4,860		13,961		5,840
Attributable to Eni		4,771		13,887		5,821
Attributable to non-controlling interest		89		74		19
Earnings per share (€ per share)	(34)
Basic		1.41		3.96		1.61
Diluted		1.40		3.95		1.60

See the accompanying notes.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (€ million)

	Note	2023	2022	2021
Profit (loss)		4,860	13,961	5,840
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans	(26)	(31)	60	119
Share of other comprehensive income (loss) on equity-accounted
investments	(26)	(2)	3	2
Change of minor investments measured at fair value with effects to
OCI	(26)	45	56	105
Tax effect	(26)	10	(5)	(77)
		22	114	149
Items that may be reclassified to profit or loss in later periods
Currency translation differences	(26)	(2,010)	1,095	2,828
Change in the fair value of cash flow hedging derivatives	(26)	541	794	(1,264)
Share of other comprehensive income (loss) on equity-accounted
investments	(26)	54	(12)	(34)
Tax effect	(26)	(158)	(234)	372
		(1,573)	1,643	1,902
Total other items of comprehensive income (loss)		(1,551)	1,757	2,051
Total comprehensive income (loss)		3,309	15,718	7,891
Attributable to Eni		3,220	15,643	7,872
Attributable to non-controlling interest		89	75	19

See the accompanying notes.

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, 2022	(26)	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 (loss)
Remeasurements of defined benefit plans net of tax effect	(26)				(21)			(21)		(21)
Share of "Other comprehensive income" on equity-accounted investments	(26)				(2)			(2)		(2)
Change of minor investments measured at fair value with effects to OCI	(26)				45			45		45
Items that are not reclassified to profit or loss in later periods					22			22		22
Currency translation differences Change in the fair value of cash flow hedge derivatives net of tax	(26)			(2,001)	(9)			(2,010)		(2,010)
effect	(26)				383			383		383
Share of "Other comprehensive income (loss)" on equity accounted investments	(26)				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 (loss) of the year				(2,001)	450		4,771	3,220	89	3,309
Dividend distribution of Eni SpA	(26)		(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	(26)		(1,837)		1,837	(1,837)		(1,837)		(1,837)
Cancellation of treasury shares	(26)				(2,400)	2,400
Long-term share-based incentive plan	(26) (30)		20		(41)	41		20		20
Coupon payment on perpetual subordinated bonds	(26)		(138)					(138)		(138)
Change in non‐controlling interest	(26)		47					47	(47)
Transactions with holders of equity instruments			8,974		(604)		604 (13,887)	(4,913)	(99)	(5,012)
Effect of the issue of convertible bonds	(26)				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	(26)	4,005	32,988	5,238	8,515	(2,333)	4,771	53,184	460	53,644

See the accompanying notes.

Table of Contents

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY continued (€ million)

		Equity attributable to equity holders of Eni
				Cumulative	Other		Profit
				currency	reserves		(loss)		Non
	Note	Share capital	Retained earnings	translation differences	and equity instruments	Treasury shares	for the year	Total	controlling interest	Total equity
Balance at December 31, 2021		4,005	22,750	6,530	6,289	(958)	5,821	44,437	82	44,519
Profit for the year							13,887	13,887	74	13,961
Other items of comprehensive income (loss)
Remeasurements of defined benefit plans net of tax effect	(26)				55			55		55
Share of "Other comprehensive income" on equity-accounted investments	(26)				3			3		3
Change of minor investments measured at fair value with effects to OCI	(26)				56			56		56
Items that are not reclassified to profit or loss in later periods					114			114		114
Currency translation differences	(26)			1,093	1			1,094	1	1,095
Change in the fair value of cash flow hedge derivatives net of tax effect	(26)				560			560		560
Share of "Other comprehensive income (loss)" on equity accounted investments	(26)				(12)			(12)		(12)
Items that may be reclassified to profit or loss in later periods				1,093	549			1,642	1	1,643
Total comprehensive income (loss) of the year				1,093	663		13,887	15,643	75	15,718
Dividend distribution of Eni SpA	(26)						(1,522)	(1,522)		(1,522)
Interim dividend distribution of Eni SpA	(26)		(1,500)					(1,500)		(1,500)
Dividend distribution of other companies									(60)	(60)
Allocation of 2021 profit			4,299				(4,299)
Capital contribution by non-controlling interests									92	92
Purchase of treasury shares	(26)		(2,400)		2,400	(2,400)		(2,400)		(2,400)
Cancellation of treasury shares	(26)				(400)	400
	(26)
Long-term share-based incentive plan	(30)		18		(21)	21		18		18
Coupon payment on perpetual subordinated bonds	(26)		(138)					(138)		(138)
Change in non‐controlling interest	(26)		196					196	281	477
Transactions with holders of equity instruments			475		1,979	(1,979)	(5,821)	(5,346)	313	(5,033)
Other changes			230	(59)	(146)			25	1	26
Other changes in equity			230	(59)	(146)			25	1	26
Balance at December 31, 2022	(26)	4,005	23,455	7,564	8,785		(2,937) 13,887	54,759	471	55,230

See the accompanying notes.

Table of Contents

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 (loss) for the year	Total	Non controlling interest	Total equity
Balance at December 31, 2020	4,005	34,043	3,895	4,688	(581)		(8,635) 37,415	78	37,493
Profit for the year						5,821	5,821	19	5,840
Other items of comprehensive income (loss)
Remeasurements of defined benefit plans net of tax effect Share of "Other comprehensive income (loss)" on equity				42			42		42
accounted investments Change of minor investments measured at fair value with effects to OCI				2 105			2 105		2 105
Items that are not reclassified to profit or loss in later periods				149			149		149
Currency translation differences			2,828				2,828		2,828
Change in the fair value of cash flow hedge derivatives net of tax effect				(892)			(892)		(892)
Share of "Other comprehensive income (loss)" on equity accounted investments				(34)			(34)		(34)
Items that may be reclassified to profit or loss in later periods			2,828	(926)			1,902		1,902
Total comprehensive income (loss) of the year			2,828	(777)		5,821	7,872	19	7,891
Dividend distribution of Eni SpA		429				(1,286)	(857)		(857)
Interim dividend distribution of Eni SpA		(1,533)					(1,533)		(1,533)
Dividend distribution of other companies								(5)	(5)
Allocation of 2020 loss		(9,921)				9,921
Purchase of treasury shares		(400)		400	(400)		(400)		(400)
Long-term share-based incentive plan		16		(23)	23		16		16
Increase in non‐controlling interest relating to acquisition of consolidated entities								(11)	(11)
Issue of perpetual subordinated bonds				2,000			2,000		2,000
Coupon payment on perpetual subordinated bonds		(61)					(61)		(61)
Transactions with holders of equity instruments		(11,470)		2,377	(377)	8,635	(835)	(16)	(851)
Costs for the issue of perpetual subordinated bonds		(15)					(15)		(15)
Other changes		192	(193)	1				1	1
Other changes in equity		177	(193)	1			(15)	1	(14)
Balance at December 31, 2021	4,005	22,750	6,530	6,289	(958)	5,821	44,437	82	44,519
See the accompanying notes.

CONSOLIDATED STATEMENT OF CASH FLOWS

(€ million)

	Note	2023	2022	2021
Profit (loss)		4,860	13,961	5,840
Adjustments to reconcile profit (loss) to net cash provided by operating activities
Depreciation and amortization	(12) (13) (14)	7,479	7,205	7,063
Net impairments (reversals) of tangible, intangible and right-of-use assets	(15)	1,802	1,140	167
Write-off of tangible and intangible assets	(12) (14)	535	599	387
Share of (profit) loss of equity-accounted investments	(16) (32)	(1,336)	(1,841)	1,091
Net gain on disposal of assets		(441)	(524)	(102)
Dividend income	(32)	(255)	(351)	(230)
Interest income		(517)	(159)	(75)
Interest expense		1,000	1,033	794
Income taxes	(33)	5,368	8,088	4,845
Other changes		(700)	(2,773)	(194)
Cash flow from changes in working capital:		1,811	(1,279)	(3,146)
- inventories		1,792	(2,528)	(2,033)
- trade receivables		3,322	(1,036)	(7,888)
- trade payables		(4,823)	2,284	7,744
- provisions		97	2,028	(406)
- other assets and liabilities		1,423	(2,027)	(563)
Change in the provisions for employee benefits		1	39	54
Dividends received		2,255	1,545	857
Interest received		459	116	28
Interest paid		(919)	(851)	(792)
Income taxes paid, net of tax receivables received		(6,283)	(8,488)	(3,726)
Net cash provided by operating activities		15,119	17,460	12,861
- of which with related parties	(36)	(7,011)	223	(4,331)
Cash flow from investing activities		(12,404)	(10,793)	(7,815)
- tangible assets	(12)	(8,739)	(7,700)	(4,950)
- prepaid right-of-use assets	(13)		(3)	(2)
- intangible assets	(14)	(476)	(356)	(284)
- consolidated subsidiaries and businesses net of cash and cash equivalents
acquired	(27)	(1,277)	(1,636)	(1,901)
- investments	(16)	(1,315)	(1,675)	(837)
- securities and financing receivables held for operating purposes		(388)	(350)	(227)
- change in payables in relation to investing activities		(209)	927	386
Cash flow from disposals		845	2,989	536
- tangible assets		122	149	207
- intangible assets		32	17	1
- consolidated subsidiaries and businesses net of cash and cash equivalents
disposed of	(27)	395	(60)	76
- tax on disposals				(35)
- investments		47	1,096	155
- securities and financing receivables held for operating purposes		32	483	141
- change in receivables in relation to disposals		217	1,304	(9)
Net change in securities and financing receivables held for non-operating
purposes		2,194	786	(4,743)
Net cash used in investing activities		(9,365)	(7,018)	(12,022)
- of which with related parties	(36)	(1,695)	(32)	(976)

CONSOLIDATED STATEMENT OF CASH FLOWS

continued (€ million)

	Note	2023	2022	2021
Increase in long-term financial debt	(19)	4,971	130	3,556
Repayments of long-term financial debt	(19)	(3,161)	(4,074)	(2,890)
Payments of lease liabilities	(13)	(963)	(994)	(939)
Increase (decrease) in short-term financial debt	(19)	(1,495)	1,375	(910)
Dividends paid to Eni's shareholders		(3,046)	(3,009)	(2,358)
Dividends paid to non-controlling interest		(36)	(60)	(5)
Capital contribution by non-controlling interests		(16)	92
Sale (purchase) of additional interests in consolidated subsidiaries		(60)	536	(17)
Purchase of treasury shares	(26)	(1,803)	(2,400)	(400)
Issueing effect of convertible bonds	(26)	79
Issue of perpetual subordinated bonds	(26)			1,985
Coupon payment on perpetual subordinated bonds	(26)	(138)	(138)	(61)
Net cash used in financing activities		(5,668)	(8,542)	(2,039)
- of which with related parties	(36)	(162)	(88)	(13)
Effect of exchange rate changes and other changes on cash and cash
equivalents		(62)	16	52
Net increase (decrease) in cash and cash equivalents		24	1,916	(1,148)
Cash and cash equivalents - beginning of the year	(6)	10,181	8,265	9,413
Cash and cash equivalents - end of the year (a)	(6)	10,205	10,181	8,265

(a) As of December 31, 2023, cash and cash equivalents included €12 million of cash and cash equivalents of consolidated subsidiaries held for sale that were reported in the item "Assets held for sale" (€26 million at December 31, 2022).

See the accompanying notes.

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 as described in the accounting policies that follow. The principles of consolidation and the significant accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated.

The 2023 Consolidated Financial Statements included in the Annual Report on Form 20-F, were approved by the Eni's Board of Directors on April 4, 2024.

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 recognised 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 2023 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 strategy towards Carbon Neutrality, in line with the provisions of the scenarios compatible with maintaining global warming within the 1.5°C threshold, 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 product portfolio. 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 decarbonisation trends, and are subject to continuous benchmarking with the views of market analysts and peers.

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).

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.

Subsidiaries are consolidated, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases.

Assets, liabilities, income and expenses of consolidated subsidiaries are fully recognised with those of the parent in the Consolidated Financial Statements, taking into account the appropriate eliminations of intragroup transactions (see the accounting policy for "Intragroup transactions"); the parent's investment in each subsidiary is eliminated against the corresponding parent's portion of equity of each subsidiary. 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.

Taking into account the lack of any material² impact on the representation of the financial position and performance of the Group³ , 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 recognised 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"). Conversely, 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 recognised 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 recognised in other comprehensive income which may be reclassified subsequently to the profit and loss account⁴ . Any investment retained in the former subsidiary is recognised at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria.

⁴Conversely, any amount related to the former subsidiary previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

²According 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".

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 recognises 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 joint venture, previously classified as joint operations are measured on the date of change in the classification of the joint arrangement at the net amount of the carrying amounts of the assets and liabilities that Eni had previously recognised, line by line, on the basis of its rights and obligations relating to the arrangement.

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".

The equity method of accounting

Investments in joint ventures, associates and immaterial unconsolidated subsidiaries, are accounted for using the equity method.⁵

Under the equity method, investments are initially recognised at cost⁶ , allocating it, similarly to business combinations procedures, 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 recognised but included in the carrying amount of the investment. If this allocation is provisionally recognised 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. Distributions received from an equity-accounted investee reduce the carrying amount of the investment. 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, recognised 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 recognised 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.

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 an investment in an equity instrument becomes an equity-accounted investee, the related cost is the sum of the fair value of the previously held equity interest in the investee and the fair value of any consideration transferred.

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 by comparing it with 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 recognised in the profit and loss account within "Income (Expense) from investments". The impairment reversal of the net investment shall not exceed the previously recognised 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 recognised as a result of the remeasurement of any investment retained in the former joint venture/associate at its fair value⁷ ; and (iii) any amount related to the former joint venture/associate previously recognised in other comprehensive income which may be reclassified subsequently to the profit and loss account⁸ . Any investment retained in the former joint venture/associate is recognised 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 includes also the fair value of any assets or liabilities resulting from contingent considerations, contractually agreed and dependent upon the occurrence of specified future events. Acquisition-related costs are accounted for as expenses.

The acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values⁹ , 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 recognised, on the balance sheet, as goodwill; conversely, a gain on a bargain purchase is recognised in the profit and loss account.

Any non-controlling interests are measured as the proportionate share in the recognised 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 recognised in the profit and loss account. Furthermore, on obtaining control, any amount recognised 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 recognised 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.

The acquisition of interests in a joint operation whose activity constitutes a business is accounted for applying the principles on business combinations accounting. In this regard, if the entity obtains control over a business that was a joint operation, the previously held interest in the joint operation is remeasured at the acquisition-date fair value and the resulting gain or loss is recognized in the profit and loss account. ¹⁰

⁷ 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 recognised in the profit and loss account.

⁸ Conversely, any amount related to the former joint venture/associate previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

⁹ Fair value measurement principles are described in the accounting policy for "Fair value measurements".

¹⁰If the entity acquires additional interests in a joint operation that is a business, while retaining joint control, the previously held interest in the joint operation is not remeasured.

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 realised with third parties, including unrealised profits arising from such transactions have been eliminated¹¹ .

Unrealised 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 unrealised 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"¹². 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.

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.

¹²When the foreign subsidiary is partially owned, the cumulative exchange difference, that is attributable to the non-controlling interests, is allocated to and recognised as part of "Non-controlling interest".

¹¹Exchange differences associated with intragroup monetary assets and liabilities arising from transactions between consolidated companies operating in different currencies are not eliminated.

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 2023	Exchange rate at December 31, 2023	Annual average exchange rate 2022	Exchange rate at December 31, 2022	Annual average exchange rate 2021	Exchange rate at December 31, 2021
U.S. Dollar	1.08	1.11	1.05	1.07	1.18	1.13
Pound Sterling	0.87	0.87	0.85	0.89	0.86	0.84
Australian Dollar	1.63	1.63	1.52	1.57	1.57	1.56

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.

Acquisition of exploration rights

Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalised 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 amortised, 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 recognised in the profit and loss account as write-off. Lower value exploration rights are pooled and amortised 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. From the commencement of production, proved exploration rights are amortised according to the unit of production method (the so-called UOP method, described in the accounting policy for "UOP depreciation, depletion and amortisation").

Acquisition of mineral interests

Costs incurred for the acquisition of mineral interests are capitalised 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.

Acquired exploration potential is measured in accordance with the criteria illustrated in the accounting policy for "Acquisition of exploration rights". Costs associated with proved reserves are amortised according to the UOP method (see the accounting policy for "UOP depreciation, depletion and amortisation"). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortised until classified as proved reserves; in case of a negative result of the subsequent appraisal activities, it is written off.

Exploration and appraisal expenditure

Geological and geophysical exploration costs are recognised as an expense as incurred.

Costs directly associated with an exploration well are initially recognised 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 capitalised in the following 12-month 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 capitalised 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; on the contrary, the capitalised costs are recognised in the profit and loss account as write-off. 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 recognised 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 amortisation").

Development costs

Development costs, including the costs related to unsuccessful and damaged development wells, are capitalised as "Tangible asset in progress — proved". Development costs are incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. They are amortised, 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".

UOP depreciation, depletion and amortisation

Proved oil and gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of proved oil and gas reserves, by applying, to the depreciable amounts at the end of each quarter a rate representing 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. This method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil and gas reserves. Proved exploration rights and acquired proved mineral interests are amortised over proved reserves; proved exploration and appraisal costs and development costs are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves. Proved reserves are determined according to U.S. SEC rules that require the use of the yearly average oil and gas prices for assessing the economic producibility; material changes in reference prices could result in depreciation charges not reflecting the pattern in which the assets' future economic benefits are expected to be consumed to the extent that, for example, certain non-current assets would be fully depreciated within a short term. In these cases the reserves considered in determining the UOP rate are estimated on the basis of economic viability parameters, reasonable and consistent with management's expectations of production, in order to recognise depreciation charges that more appropriately reflect the expected utilization of the assets concerned.

Production costs

Production costs are those costs incurred to operate and maintain wells and field equipment and are recognised as an expense as incurred.

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 recognise 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 capitalised, 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 Company's 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 categorised as "proved", the accuracy of reserve estimates depends on a number of factors, assumptions and variables, including: (i) the quality of available geological, technical and economic 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 estimates which may drive substantial upward or downward revisions; 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 and costs 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 uncertanties 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 capitalised 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 categorised 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 proved reserves are used in determining depreciation, amortisation and depletion charges (see the accounting policy for "UOP depreciation, depletion and amortisation") judgment. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, amortisation and depletion charge under the UOP method. Conversely, a decrease in estimated proved developed reserves increases depreciation, amortisation and depletion charge.

Property, plant and equipment

Property, plant and equipment, including investment properties, 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 management¹³ .

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 recognised as part of a specific provision (see the accounting policy for "Decommissioning and restoration liabilities"). Analogous approach is adopted for present obligations to realise social projects in oil and gas development areas.

Property, plant and equipment are not revalued for financial reporting purposes.

Expenditures on upgrading, revamping and reconversion are recognised 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.

¹³In some cases, the acquisition of an item of property, plant and equipment provides for an initial payment plus additional payments that are contingent on future events or outcomes (the so-called contingent consideration). In such cases, on the acquisition date an item of property, plant and equipment is recognised at an amount of consideration paid. Therefore, the variable payments contingent on future events are not included in the acquisition cost. The liability for contingent consideration is recognised, as a contra to the related asset, when it becomes due, i.e. when the uncertainty to which it relates is resolved.

Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. 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. Land is not depreciated, even when acquired together with a building. Tangible assets held for sale are not depreciated (see the accounting policy for "Assets held for sale and discontinued operations"). 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.

Assets to be handed over for no consideration are depreciated over the shorter term between the duration of the concession or the asset's useful life.

Replacement costs of identifiable parts in complex assets are capitalised 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 recognised as an expense as incurred.

The carrying amount of property, plant and equipment is derecognised 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 ¹⁴

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 consideration¹⁵; 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 commencement date of the lease (i.e. the date on which the underlying asset is available for use), a lessee recognises on the balance sheet an asset representing its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability representing its obligation to make lease payments during the lease term (hereinafter also referred as lease liability).¹⁶ 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.

¹⁴As expressly provided for in IFRS 16, 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.

¹⁵The assessment of whether the contract is, or contains, a lease is performed at the inception date, that is the earlier of the date of a lease agreement and the date of commitment by the parties to the principal terms and conditions of the lease.

¹⁶ Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognising the lease payments associated with those leases as an expense on a straight-line basis over the lease term.

In particular, the lease liability is initially recognised at the present value of the following lease payments¹⁷ that are not paid at the commencement date: (i) fixed payments (including in-substance fixed payments), less any lease incentives receivable; (ii) variable lease payments that on an index or a rate¹⁸; (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 amortised 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 contractual options (e.g. options to purchase the underlying asset, extension or termination options).

The right-of-use asset is initially measured at cost, which comprises: (i) the amount of the initial measurement of the lease liability; (ii) any initial direct costs incurred by the lessee¹⁹; (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 for any accumulated depreciation²⁰, any accumulated impairment losses (see the accounting policy for "Impairment of non-financial assets") and any remeasurement of the lease liability.

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 capitalised as part of the cost of such asset and subsequently recognised in the profit and loss account through depreciation/impairments or write-off, mainly in the case of exploration assets.

In the oil and gas activities, the operator of an unincorporated joint operation which enters into a lease contract as the sole signatory recognises 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, recognised 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 recognised 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.

²⁰ Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the rightof-use asset or the end of the lease term. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee by the end of the lease term, or if the cost of the right-of-use asset reflects that the lessee 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.

¹⁷Eni, in accordance with the practical expedient allowed by the accounting standard, 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.

¹⁸Conversely, the other kinds of variable lease payments (e.g. payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability, but are recognised in the profit and loss account as operating expenses over the lease term.

¹⁹Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained.

Differently, if a lease contract is signed by all the partners, Eni recognises 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 recognise 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 recognise 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) recognising 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 recognised 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 amortised on a systematic basis over their useful life; the amortisation 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 amortised. 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 recognised on the balance sheet if the Company expects to recover those costs. The carrying value of the intangible asset arising from those costs is amortised 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 devolpement costs related to CCS Projects (Carbon, Capture and Storage) incurred before the construction of the physical infrastucture, are capitalised 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 derecognised on disposal or when no future economic benefits are expected from its use or disposal; any arising gain or loss is recognised in the profit and loss account.

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. 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. 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.

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 expected cash flows are determined on the basis of reasonable and supportable assumptions that represent management's best estimate of the range of economic conditions that will exist over the remaining useful life of the CGU, giving greater weight to external evidence.

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.

With reference to commodity prices, management uses the price scenario adopted for economic and financial projections and for the evaluation of investments over their entire life. In particular, for the cash flows associated with oil, natural gas and petroleum products prices (and prices derived from them), the price scenario is approved by the Board of Directors (see "Significant accounting estimates and judgments used to take into account the impacts of climate-related risks").

For impairment test purposes, cash outflows expected to be incurred to guarantee compliance with laws and regulations regarding CO2 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 projects²¹ 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 Global Gas & LNG Portfolio (GGP) operating segment, the Chemicals, Power business, E-Mobility, Retail Domestic and Renewable businesses, Fuel Sales, Biomethane and Green Refinery businesses, the Agri-Feedstock Business and Eni Rewind business, the riskiness is determined on the basis of a sample of comparable companies. For the E&P operating segment and REVT (Refining Evolution and Transformation) 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.

²¹ For the recognition criteria of forestry certificates see the accounting policy for "Costs".

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 recognised 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 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. An impairment loss recognised for goodwill is not reversed in a subsequent period.²²

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 realisable value. Net realisable 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 recognised 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 Chemicals business is determined by applying the weighted average cost on an annual basis.

²²Impairment losses recognised for goodwill in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognised in a smaller amount or would not have been recognised.

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 recognised 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 realisable value, determined adopting the same criteria described for inventories.

Significant accounting estimates and judgments: impairment of non-financial assets

The recoverability of non-financial assets is assessed whenever events or changes in circumstances indicate that carrying amounts of the assets may not be recoverable. Such impairment indicators include, for example, changes in the Group's business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilisation of plants and, for oil and gas properties, significant downward revisions of estimated reserve quantities or significant increase of the estimated development and production costs. Determination as to whether and how much an asset is impaired involves 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. 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, require judgment by management. 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 recognised 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 determination 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. In particular, taking into consideration the current and expected decarbonisation trends, the estimate of expected future cash flows, which considers Eni's scenarios for commodities price, 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 specialised institutions. Such cash flows are discounted using a rate which considers the risks specific to the asset.

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, market demand and other factors.

More details on the main assumptions underlying the determination of the recoverable amount of tangible, intangible and right-of-use assets are set out in note 15 – Reversals (Impairments) of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonisation scenarios.

Financial instruments

Financial assets

Financial assets 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 amortised cost; (ii) financial assets measured at fair value through other comprehensive income (hereinafter also OCI); (iii) financial assets measured at fair value through profit or loss (hereiafter 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 amortised 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 amortised cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses²³ (see the accounting policy for "Impairment of financial assets") are recognised in the profit and loss account.

Conversely, financial assets that are debt instruments are measured at fair value through OCI (hereinafter also FVTOCI) if they are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets (the so-called hold to collect and sell business model). In these cases: (i) 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 recognised in the profit and loss account; (ii) changes in fair value of the instruments are recognised in equity, within other comprehensive income. The accumulated changes in fair value, recognised in the equity reserve related to other comprehensive income, is reclassified to the profit and loss account when the financial asset is derecognised. Currently the Group does not have any financial assets measured at fair value through OCI.

²³Receivables and other financial assets measured at amortised cost are presented on the balance sheet net of their loss allowance.

A financial asset represented by a debt instrument that is neither measured at amortised cost nor at FVTOCI, is 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 recognised 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.²⁴

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.

²⁴The 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 recognised on issued guarantees are not material.

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.²⁵

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 recognised 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 held for operating purposes, 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 recognised in the profit and loss account, within the line item "Income (Expense) from investments", unless they clearly represent a recovery of part of the cost of the investment. In limited circumstances, an investment in equity instruments can be measured at cost if it is an appropriate estimate of fair value.

²⁵For credit exposures arising from intragroup transactions, the recovery rate is normally assumed equal to 100% taking into account, inter alia, the Group central treasury function which supports both financial and capital needs of subsidiaries.

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 amortised 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 amortised 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 amortised cost, and by the conversion option, recognised 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 as a financial liability determines: (i) upon reclassification/initial recognition of the liability, a non-monetary change in financial liabilities, 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, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value.

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 recognised 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, recognised 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 derivatives that are not designated as hedging instruments, including any ineffective portion of changes in fair value of hedging derivatives, are recognised in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognised 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 recognised 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"). Derivatives embedded in financial liabilities and/or non-financial assets are separated if: (i) the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract; (ii) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and (iii) the entire hybrid contract is not measured at FVTPL.

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 recognised on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

Offsetting of financial assets and liabilities

Financial assets and liabilities are set off on the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realise the asset and settle the liability simultaneously).

Derecognition of financial assets and liabilities

Transferred financial assets are derecognised when the contractual rights to receive the cash flows from the financial assets expire or are transferred to another party. Financial liabilities are derecognised when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired.

Provisions, contingent liabilities and contingent assets

A provision is a liability of uncertain timing or amount on the balance sheet date. Provisions are recognised 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 recognised as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties on the balance sheet date. The amount recognised 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 recognised within "Finance income (expense)" in the profit and loss account.

A provision for restructuring costs is recognised 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. Changes in provisions are recognised in the same profit and loss account line item where the original provision was charged.

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 recognised in the financial statements but are disclosed.

Contingent assets, that are possible assets arising from past events and 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, are not recognised in financial statements unless the realisation of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements.

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, when the conditions indicated in the accounting policy for "Provisions, contingent liabilities and contingent assets" are met.

Considering the long time span between the recognition of the obligation and its settlement, the amount recognised is the present value of the future expenditures expected to be required to settle the obligation. Any change due to the unwinding of discount on provisions is recognised within "Finance income (expense)".

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 recognised 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 recognised in the profit and loss account.

Analogous approach is adopted for present obligations to realise social projects related to operating activities carried out by the Company.

Environmental liabilities

Environmental liabilities are recognised when the Group has a present obligation, legal or constructive, 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. Liabilities for environmental costs are recognised when a clean-up is probable and the associated costs can be reliably estimated. 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 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.

The estimates about the timing and amount of future cash outflows, any related update as well as the related discounting are based on complex managerial judgments.

Decommissioning and restoration provisions, recognised 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, wellplugging, 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 recognised 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.

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. Environmental liabilities are recognised when it becomes probable that an outflow of resources will be required to settle the obligation and such obligation can be reliably estimated. 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, where supported by adequate estimates.

Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provisions already recognised, 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.

In addition to environmental and decommissioning and restoration liabilities, Eni recognises provisions primarily related to legal and trade proceedings. These provisions are estimated on the basis of complex managerial judgments related to the amounts to be recognised and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate.

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.

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 recognised 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 recognised within the statement of comprehensive income. Remeasurements of the net defined benefit liability, recognised 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 recognised 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 recognises 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-empoyment 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 recognised; 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.

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. 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 recognised 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.

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 utilisation, 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, are recognised as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognised 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 interest²⁶. Therefore, the issuer recognises the cash received from the bondholders, net of costs incurred in issuing the hybrid bonds, as an increase in Eni owners' equity; 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 recognised on the basis of the following five steps: (i) identifying the contract with the customer; (ii) identifying the performance obligations, that are promises in a contract to transfer goods and/or services to a customer; (iii) determining the transaction price; (iv) allocating the transaction price to each performance obligation on the basis of the relative stand-alone selling prices of each good or service; and (v) recognising revenue when (or as) a 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 recognised for:

• crude oil, upon shipment;
• natural gas 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 recognised upon shipment; and
• chemical products and other products, upon shipment.

²⁶The 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.

Revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers is recognised on the basis of the quantities actually lifted and sold (sales method); costs are recognised on the basis of the quantities actually sold.

Revenue is measured at the fair value of 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. In determining the transaction price, the promised amount of consideration is adjusted for the effects of the time value of money if the timing of payments agreed to by the parties to the contract provides the customer or the entity with a significant benefit of financing the transfer of goods or services to the customer. The promised amount of consideration is not adjusted for the effect of the significant financing component if, at contract inception, it is expected that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. 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 recognised.

Costs

Costs are recognised when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) and determined on the basis of market prices, are recognised 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 recognised as intangible assets. Revenue related to emission quotas is recognised when they are sold. Emission rights held for trading are recognised 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 recognised in the profit and loss account when incurred.

The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalised (see also the accounting policy for "Intangible assets"), are included in the profit and loss account when they are 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 recognised. 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 realisable value are retranslated using the exchange rate at the date when the value is determined.

Dividends

Dividends are recognised 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.

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 recognised 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 realised 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 recognised 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 recognised to the extent that their recoverability is probable. The carrying amount of the deferred tax assets is reviewed, at least, on an annual basis.

If there is uncertainty over income tax treatments, if the company 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 recognised in the financial statements consistent with the tax treatment used or planned to be used in its income tax filings. Conversely, if the company 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 recognised in the financial statements.

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 recognised 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. Deferred tax assets and liabilities are presented within non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognised in the line item "Deferred tax assets" and, if negative, in the line item "Deferred tax liabilities". When the results of transactions are recognised in other comprehensive income or directly in equity, the related current and deferred taxes are also recognised 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 characterised 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.

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 and discontinued operations

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. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale.

Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognised on the balance sheet separately from other assets and liabilities.

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 amortised and they are measured at the lower of the fair value less costs to sell and their carrying amount. If an equity-accounted investment, or a portion of that investment meets the criteria to be classified as held for sale, it is no longer accounted for using the equity method and it is measured at the lower of its carrying amount at the date the equity method is discontinued, and its fair value less costs to sell. Any retained portion of the equityaccounted investment that has not been classified as held for sale is accounted for using the equity method until disposal of the portion that is classified as held for sale takes place.

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 recognised up to the cumulative impairment losses, including those recognised prior to qualification of the asset as held for sale. Non-current assets classified as held for sale and disposal groups are considered a discontinued operation if they, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognised on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements.

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, amortisation, impairment losses and reversals that would have been recognised 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 (not in a forced liquidation or a distress sale) at the measurement date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity's intention to sell the asset or transfer the liability to be measured.

A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity's current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximise the value of the asset.

The fair value of a liability, both financial and non-financial, or of the Company's own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty's credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the Company's own credit risk for a financial liability (Debit Valuation Adjustment, DVA). In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximising the use of relevant observable inputs and minimising the use of unobservable inputs.

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 directlyor 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

Assets and liabilities on the balance sheet are classified as current and non-current. Items in the profit and loss account are presented by nature.

The balance sheet and the profit and loss account are the same of the ones used in the previous reporting period.

The statement of comprehensive income (loss) shows net profit integrated with income and expenses that are not recognised directly in the profit and loss account according to IFRSs.

The statement of changes in equity includes the total comprehensive income (loss) for the year, transactions with owners in their capacity as owners and other changes in equity.

The statement of cash flows is presented using the indirect method, whereby net profit (loss) is adjusted for the effects of non-cash transactions.

3 Changes in accounting policies

The amendments to IFRSs, as well as the requirements of IFRS 17 "Insurance Contracts", effective from January 1, 2023, did not have a material impact on the Consolidated Financial Statements.

The Italian Legislative Decree No. 209/2023 of December 19, 2023 adopted the EU Directive 2022/2523; such Directive, implementing the Pillar Two model rules published by OECD, ensures a global minimum level of taxation for multinational enterprise groups providing for the application of a top-up tax on income in countries characterized by taxation levels lower than the minimum one.

During the year, analyses, on the basis of current data and prospective assumptions, have been performed to assess any material exposure for the Group to the payment of top-up tax with reference to countries in which the Group operates; at the current stage of the analyses, the Group does not expect significant impacts arising from the requirements of the new tax measures which shall be effective starting from January 1, 2024. On this regard, Eni, for the preparation of 2023 Consolidated Financial Statements, has applied the amendments to IAS 12 "International Tax Reform- Pillar Two Model Rules" aimed to provide, in addition to specific disclosure requirements, a mandatory temporary exception from accounting for deferred taxes arising from enacted or substantially enacted tax laws that implement the Pillar Two model rules published by the OECD.

4 IFRSs not yet effective

On January 23, 2020 and on October 31, 2022, respectively, the IASB issued the amendments to IAS 1 "Classification of Liabilities as Current or Non-current" and "Non-current Liabilities with Covenants", which clarify: (i) how to classify debt and other liabilities as current or non-current; and (ii) how to classify, as current or non-current, liabilities with covenants. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2024.

On September 22, 2022, the IASB issued the amendments to IFRS 16 "Lease Liability in a Sale and Leaseback" aimed to clarify the subsequent measurement of lease liabilities arising from sale and leaseback transactions. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2024.

On May 25, 2023, the IASB issued the amendments to IAS 7 "Statement of Cash Flows" and IFRS 7 "Financial Instruments: Disclosures: Supplier Finance Arrangements" aimed to introduce disclosure requirements about supplier finance arrangements (e.g. reverse factoring) that enable investors to assess the effects of those arrangements on the buyer's liabilities, cash flows and exposure to liquidity risk. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2024.

On August 15, 2023, the IASB issued the amendments to IAS 21 "The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability" aimed, substantially, to require the estimate of a spot exchange rate when a currency is not exchangeable into another currency. The amendments are effective for annual reporting periods beginning on or after January 1, 2025.

Eni is currently reviewing the IFRSs not yet effective in order to determine the likely impact on the Consolidated Financial Statements.

5 Business combinations and other significant transactions

Acquisitions

In 2023, Eni executed the acquisitions represented below with an outlay of €1,432 million, assuming net financial liabilities of €91 million, of which cash and cash equivalents for €155 million.

Plenitude business line

On January 30, 2023, Eni purchased the Kellam photovoltaic plant with an installed capacity of 81 MW located in North Texas. The consideration of the transaction amounted to €37 million with assumption of net financial liabilities of €2 million, of which cash and cash equivalents for €1 million. The price allocation of the acquired net assets was made on a provisional basis without recognition of goodwill.

On February 9, 2023, Eni acquired the Spanish company Maristella Directorship SLU, owner of a solar energy project with a capacity of 90 MWp. The consideration of the transaction amounted to €5 million, which were allocated to property, plant and equipment in progress.

On May 11, 2023, Eni acquired two Spanish companies, Wind Hero SLU and Wind Grower SLU, which have the rights to develop two solar energy projects with a capacity of 50 MW each. The consideration of the transaction amounted to €8 million, of which €4 million paid as advance in 2022.

On June 21, 2023, Eni acquired two Spanish companies, HLS Bonete PV SLU and HLS Bonete Topco SLU, which are operating two photovoltaic plants with a total capacity of 96 MWp. The consideration of the transaction amounted to €118 million with assumption of cash and cash equivalents for €22 million. The price allocation of the acquired net assets was made on a provisional basis with recognition of goodwill for €6 million.

On October 5, 2023, Eni acquired three Spanish companies, Boceto Solar SLU, Cornisa Solar SLU e Ladronera Solar SLU, which have the rights to build photovoltaic assets with a total capacity of 150 MW. Construction activities are planned to start shortly. The consideration of the transaction amounted to €25 million, of which €4 million paid as advance in 2021.

On October 23, 2023, Eni acquired the Spanish company Renopool 1 SLU, owner of a pipeline of solar energy projects with a total capacity of 330 MW in a "Ready to Build" status. The consideration of the transaction amounted to €100 million with assumption of net financial liabilities for €20 million, of which cash and cash equivalents for €6 million.

On December 13, 2023, Eni acquired the Spanish company Armadura Solar SLU, owner of a solar energy project with a capacity of 250 MW. The consideration for the transaction amounted to €24 million, net of advances for €19 million paid before closing of the transaction.

On December 13, 2023, Eni acquired five Spanish companies, Almazara Solar SLU, Atlante Solar SLU, Chapitel Solar SLU, Fortaleza Solar SLU and Garita Solar SLU, which have the rights to develop solar energy project with a total capacity of 230 MW. The consideration of the transaction amounted to €26 million, net of advances for €21 million paid before the closing of the transaction.

On December 30, 2023 Plenitude, through its subsidiary Eni New Energy US Inc, signed an agreement with the global leader company in the energy sector EDP Renováveis, SA ("EDPR") for the acquisition of 80% of three already operational photovoltaic systems located in the United States. In this regard, the Cattlemen (Texas) and Timber Road Blue Harvest (Ohio) parks have a total installed capacity of 0.38 GW of Plenitude's share.

Other minor acquisitions and price adjustments on 2022 acquisitions totalled €21 million.

Exploration & Production segment

On February 28, 2023, Eni closed the acquisition of the BP business in Algeria, including the two gas-producing concessions "In Amenas" (Eni In Amenas Ltd) and "In Salah" (Eni In Salah Ltd), jointly operated with Sonatrach and Equinor. The consideration of the transaction amounted to €476 million. Price allocation of the net assets acquired was made on a definite basis and without recognition of goodwill, attributing the allocated consideration to tangible assets to unproven and proven mining titles for €40 million for €508 million.

On October 2, 2023, Eni farmed in the working interests of Chevron and the operatorship in the Ganal PSC (62%), the Rapak PSC (62%) and the Makassar Straits PSC (72%) blocks in the Kutei Basin, East Kalimantan, offshore Indonesia (Ganal and Rapak), where Eni already retained a participating interest of 20%. The consideration for the transaction was €188 million, with assumption of net financial assets for €120 million, of which cash and cash equivalents for €122 million. The price allocation of the acquired net assets was made on a definite basis without recognition of goodwill by allocating to tangible assets to unproved mining titles for €91 million and €13 million to proved property.

Chemicals business line

On October 18, 2023, Eni closed the acquisition of control of Novamont by purchasing the remaining 64% of the share capital (already owned by Versalis SpA with a 36% stake). The group is engaged in the production of resins and biodegradable plastics derived from renewable feedstock. The consideration for the purchase of 64% was €404 million, with assumption of net financial liabilities for €207 million, of which cash and cash equivalents for €4 million. The allocation of the purchase price (€404 million) and the fair value of the stake already owned (€227 million) of the acquired net assets was made on a provisional basis with the recognition of goodwill of €19 million.

Balance sheet values at the acquisition date of the business combinations realized in 2023 are shown in the following table:

		Exploration
(€ million)	Plenitude	&	Chemicals
	business line	Production segment	business line	Total
Cash and cash equivalents	29	122	4	155
Other current assets	5	208	195	408
Current assets	34	330	199	563
Property, plant and equipment	168	652	255	1,075
Goodwill	6		19	25
Deferred tax assets	3		33	36
Other non-current assets	259	91	524	874
Non-current assets	436	743	831	2,010
TOTAL ASSETS	470	1,073	1,030	2,573
Current financial liabilities	1		103	104
Other current liabilities	9	125	184	318
Current liabilities	10	125	287	422
Non-current financial liabilities	32	2	108	142
Provisions	2	86		88
Deferred tax liabilities	13	195		208
Other non-current liabilities	3	1	4	8
Non-current liabilities	50	284	112	446
TOTAL LIABILITIES	60	409	399	868
Equity attributable to Eni	408	664	631	1,703
Non-controlling interest	2			2
TOTAL EQUITY	410	664	631	1,705
TOTAL LIABILITIES AND EQUITY	470	1,073	1,030	2,573

For transactions where the purchase allocations are provisional as of December 31, 2023, not all the relevant information has been obtained by the Company in order to finalize related estimates of the fair values of certain assets and liabilities acquired.

Information about the definitive purchase price allocation of business combinations made in 2022 is provided in note 27 ‐ Other Information.

Divestments

In 2023, Eni closed the divestment of certain subsidiaries and investments receiving in exchange a cash consideration of €420 million and an interest in a joint ventures valued at €580 million, also dismissing net financial liabilities for €180 million, of which cash and cash equivalents of €25 million.

On January 10, 2023, Eni closed the sale to Snam of 49.9% of the equity interest directly and indirectly held in the companies operating two groups of international gas pipelines connecting Algeria to Italy, including an onshore gas pipeline running from the Algeria border to the Tunisian coast (TTPC) and an offshore gas pipelines connecting the Tunisian coast to Italy (TMPC), reclassified to assets held for sale in 2022. This transaction led to establishing the joint venture SeaCorridor Srl and the consequent derecognition of net assets and liabilities for €331 million, of which net financial assets of €172 million, including cash and cash equivalents for €25 million, the recognition of the investment in SeaCorridor Srl (Eni share 50.1%) for €580 million and a capital gain realized from the sale to Snam of the 49.9% share of the capital of SeaCorridor Srl for €420 million, including the realization of positive exchange differences for €7 million. Furthermore, Eni realized a capital gain from the fair value valuation of the remaining 50.1% share of the capital of SeaCorridor Srl for €414 million.

On September 19, 2023, Eni divested its exploration activities in Gabon, reclassified to assets held for sale in 2022. The transaction involved the sale of Eni Gabon SA and the derecognition of net financial assets for €8 million, while a capital gain for €7 million was recognized through profit and loss.

Balance sheet values of the divestments and/or business combinations realized in 2023 are shown in the following table:

(€ million)	EniCorridor Srl (now SeaCorridor Srl)	Exploration activities in Gabon	Total
Cash and cash equivalents	25		25
Current financial assets	147	8	155
Other current assets	130		130
Current assets	302	8	310
Property, plant and equipment	8		8
Deferred tax assets	8		8
Other non-current assets	137		137
Non-current assets	153		153
TOTAL ASSETS	455	8	463
Other current liabilities	112		112
Current liabilities	112		112
Other non-current liabilities	12		12
Non-current liabilities	12		12
TOTAL LIABILITIES	124		124
Equity attributable to Eni	331	8	339
TOTAL EQUITY	331	8	339
TOTAL LIABILITIES AND EQUITY	455	8	463

6 Cash and cash equivalents

Cash and cash equivalents of €10,193 million (€10,155 million at December 31, 2022) included financial assets with maturity of up to three months at the date of inception amounting to €6,462 million (€6,804 million at December 31, 2022) and mainly included deposits with financial institutions, having notice of more than 48 hours.

Expected credit losses on deposits with banks and financial institutions measured at amortized cost were immaterial.

Cash and cash equivalents mainly consisted of deposits in US dollars (€7,328 million) and in euros (€1,945 million) representing the use of cash on hand in the market for the financial needs of the Group.

Restricted cash amounted to €205 million (€97 million at December 31, 2022) 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 12 days with an effective interest rate of 5.48% for bank deposits in U.S. dollars (€5,275 million) and 55 days with an effective interest rate of 3.87% for bank deposits in euros (€598 million).

7 Financial assets at fair value through profit or loss

	December	December
	31,	31,
(€ million)	2023	2022
Bonds issued by sovereign states	1,250	1,244
Other	5,196	5,243
Financial assets held for trading	6,446	6,487
Other financial assets at fair value through profit or loss	336	1,764
Total financial assets at fair value through profit or loss	6,782	8,251

The Company has established a liquidity reserve as part of its internal targets and financial strategy with a view of ensuring an adequate level of flexibility to the Group development plans and of matching unplanned fund requirements or managing 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.

Financial assets held for trading include securities subject to lending agreements of €1,288 million (€1,090 million at December 31, 2022).

The breakdown by currency is provided below:

	December 31,	December 31,
(€ million)	2023	2022
Euro	3,766	3,599
U.S. dollars	2,680	2,885
Other currencies		3
Financial assets held for trading	6,446	6,487
Euro	200	1,201
U.S. dollars	136	563
Other financial assets at fair value through profit or loss	336	1,764
Total financial assets at fair value through profit or loss	6,782	8,251

The breakdown by issuing entity and credit rating is presented below:

	Nominal value	Fair Value	Rating -	Rating -
	(€ million)	(€ million)	Moody's	S&P
Quoted bonds issued by sovereign states
Fixed rate bonds
Italy	178	180	Baa3	BBB
United States of America	603	536	Aaa	AA+
Spain	166	170	Baa1	A
Canada	65	59	Aaa	AAA
France	58	58	Aa2	AA
			from Aaa to	from AAA to
Other (*)	96	89	A3	A
	1,166	1,092
Floating rate bonds
Italy	155	158	Baa3	BBB
	155	158
Total quoted bonds issued by sovereign states	1,321	1,250
Other Bonds
Fixed rate bonds
			from Aaa to	from AAA to
Quoted bonds issued by industrial companies	1,995	1,885	Baa2	BBB
Quoted bonds issued by financial and insurance			from Aaa to	from AAA to
companies	819	788	Baa3	BBB
			from Aaa to	from AAA to
Other bonds	1,023	1,007	Baa3	BBB
	3,837	3,680
Floating rate bonds
Quoted bonds issued by financial and insurance			from Aaa to	from AAA to
companies	629	616	Baa2	BBB
			from Aa2 to	from AA to
Quoted bonds issued by industrial companies	469	452	Baa3	BBB
			from Aaa to	from AAA to
Other bonds	476	448	Baa2	BBB
	1,574	1,516
Total other bonds	5,411	5,196
Total financial assets held for trading	6,732	6,446
Other financial assets at fair value through profit or				from AAAm
loss	350	336		to BBB
	7,082	6,782

(*) 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 is level 1 for €5,106 million and level 2 for €1,340 million. The fair value hierarchy for Other financial assets measured at fair value with effects to profit or loss is level 2. During 2023, there were no significant transfers between the different hierarchy levels of fair value.

8 Trade and other receivables

	December	December
	31,	31,
(€ million)	2023	2022
Trade receivables	13,184	16,556
Receivables from joint ventures in exploration and production activities	1,365	1,645
Receivables from divestments	200	301
Other receivables	1,802	2,338
Total trade and other receivables, net of allowance for doubtful accounts	16,551	20,840

Generally, trade receivables do not bear interest and provide payment terms within 180 days.

The decrease in trade receivables of €3,372 million referred to the segments Global Gas & LNG Portfolio for €3,889 million and Plenitude & Power for €267 million partially offset by the increase in the segments Exploration & Production for €620 million and Enilive, Refining and Chemicals for €103 million. The decrease in the Global Gas & LNG Portfolio and Plenitude & Power reflected the decline in the prices of energy commodities, which decreased the nominal value of the receivables.

At December 31, 2023, Eni factored without recourse receivables due in 2024 with a nominal value of €1,745 million (€2,212 million at December 31, 2022 due in 2023). Derecognized receivables in 2023 related to the segments Enilive, Refining and Chemicals for €1,291 million, Global Gas & LNG Portfolio for €297 million and Plenitude & Power segment for €157 million.

At the balance sheet date Eni owned €1,156 million of net trade receivables, part of which past due, towards Egyptian state oil companies in relation to supplies of equity hydrocarbons, mainly natural gas. The accumulation in trade receivables has accelerated in the second half of the year because of the rapid deterioration of the country's economic and financial situation, worsened by the crisis in the Middle East, which led to a contraction in foreign exchange reserves leading to a slowdown in the payments of receivables owed to oil companies operating in the country. On the basis of the commitments of the country's authorities to normalize the outstanding exposure towards Eni, an expected credit loss was estimated taking into account the expected timing of collection.

At December 31, 2023, a past due trade receivable for the supply of natural gas to the customer Acciaierie d'Italia (former ILVA) was outstanding for an amount of €75 million (€373 million at December 31, 2022). A parent company guarantee has been issued by the shareholders of the debtor, which cover the entire amount of the receivable.

Receivables owed to Eni by joint operators in Nigeria have been reclassified to assets held for sale because of the ongoing divestment of the Nigerian subsidiary NAOC, whose assets included past due net receivables amounting to €236 million at December 31, 2023, which are owed to Eni by the counterparty of the possible transaction (see note 25 – Assets held for sale and liabilities directly associated with assets held for sale). Those receivables were in respect to the share of development costs of the joint operators in oil projects operated by Eni. The assets of the held-for-sale subsidiary also included overdue receivables owed to Eni by the Nigerian state oil company NNPC for €472 million (€475 million at December 31, 2022). About 85% of such amount related to net receivables accrued for unpaid cash calls, for which an expected credit loss has been estimated by considering the average timing of repayment in the case of state-owned companies. The remaining part related to past overdue receivables, the collection of which has been almost entirely finalized thanks to a repayment plan which awarded Eni the share of profit oil of the state-owned company in low-risk "rig-less" development initiatives with total collection expected by end of 2024. The residual amount outstanding at the end of the year has been discounted by using the country WACC (Weighted Average Cost of Capital).

Receivables from other counterparties comprised several miscellaneous items. The two largest amounts were: (i) the recoverable amount of €600 million (€566 million at December 31, 2022) of overdue trade receivables owed to Eni by the stateowned oil company of Venezuela, PDVSA, in relation to equity volumes of natural gas supplied to PDVSA by the joint venture Cardón IV, equally participated by Eni and Repsol. Those trade receivables were divested by the joint venture to the two shareholders. The receivables were stated net of an allowance for doubtful accounts, calculated with an expected credit loss rate deemed suitable to discount the sovereign risk and assuming a structural delay in collecting natural gas invoices. During the year, under the approval of US authorities within the context of the sanctions framework against Venezuela, receivables were collected under a barter scheme, which provided Eni with the right to lift crude oil volumes part of PDVSA entitlements for 5.6 million barrels, thus limiting the increase in overdue amounts; (ii) prepayments for services of €358 million (€278 million at December 31, 2022); (iii) €231 million (€239 million at December 31, 2022) of the amounts to be received from customers following the triggering of the take-or-pay clause of long-term natural gas supply contracts; (iv) receivables owed to Eni by Italian local distributors of natural gas and electricity of €309 million as of December 31, 2022 were entirely collected as certain measures expired, which were enacted by the Italian State in 2022 to reduce the cost of the energy bill to households and businesses; (v) €6 million (€193 million at December 31, 2022) of receivables from factoring companies. The remaining amount was composed of miscellaneous balances for approximately €753 million.

Trade and other receivables stated in euro and U.S. dollars amounted to €9,915 million and €6,041 million, respectively.

Credit risk exposure and expected losses relating to trade and other receivables has been prepared on the basis of internal ratings as follows:

	Performing receivables
		Medium		Defaulted	Plenitude
(€ million)	Low risk	Risk	High Risk	receivables	customers	Total
December 31, 2023
Business customers	3,577	5,303	331	909		10,120
National Oil Companies and Public
Administrations	215	634	168	2,438		3,455
Other counterparties	1,103	616	10	590	2,995	5,314
Gross amount	4,895	6,553	509	3,937	2,995	18,889
Allowance for doubtful accounts	(19)	(72)	(23)	(1,668)	(556)	(2,338)
Net amount	4,876	6,481	486	2,269	2,439	16,551
Expected loss (% net of counterpart
risk mitigation factors)	0.4	1.1	4.5	42.4	18.6	12.4
December 31, 2022
Business customers	4,815	7,970	378	1,583		14,746
National Oil Companies and Public
Administrations	215	852		2,248		3,315
Other counterparties	1,673	725	13	122	3,200	5,733
Gross amount	6,703	9,547	391	3,953	3,200	23,794
Allowance for doubtful accounts	(23)	(169)	(15)	(2,176)	(571)	(2,954)
Net amount	6,680	9,378	376	1,777	2,629	20,840
Expected loss (% net of counterpart
risk mitigation factors)	0.4	1.8	3.8	55.0	17.8	12.4

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.

The assessments of the recoverability of trade receivables for the supply of hydrocarbons, products and power to retail, business customers and national oil companies and of receivables towards joint operators of the Exploration & Production segment for cash calls (national oil companies, local private operators or international oil companies) are reviewed periodically to reflect the current economic environment and business trends, as well as any possible increase in the counterparty risks.

The exposure to credit risk and expected losses relating to customers of Plenitude was assessed based on a provision matrix as follows:

		from 0	from 3	from 6	over
(€ million)	Not-past due	to 3 months	to 6 months	to 12 months	12 months	Total
December 31, 2023
Plenitude customers:
- Retail	1,477	107	45	93	207	1,929
- Middle	716	39	7	11	134	907
- Other	149	4	1	4	1	159
Gross amount	2,342	150	53	108	342	2,995
Allowance for doubtful accounts	(72)	(40)	(38)	(76)	(330)	(556)
Net amount	2,270	110	15	32	12	2,439
Expected loss (%)	3.1	26.7	71.7	70.4	96.5	18.6
December 31, 2022
Plenitude customers:
- Retail	1,508	74	35	63	203	1,883
- Middle	657	33	11	7	162	870
- Other	436	1	5	4	1	447
Gross amount	2,601	108	51	74	366	3,200
Allowance for doubtful accounts	(83)	(31)	(31)	(66)	(360)	(571)
Net amount	2,518	77	20	8	6	2,629
Expected loss (%)	3.2	28.7	60.8	89.2	98.4	17.8

The following table analyses the allowance for doubtful accounts for trade and other receivables:

(€ million)	2023	2022
Allowance for doubtful accounts - beginning of the year	2,954	3,313
Additions for trade and other performing receivables	160	166
Additions for trade and other defaulted receivables	342	253
Utilizations for trade and other performing receivables	(140)	(37)
Utilizations for trade and other defaulted receivables	(485)	(758)
Other changes	(493)	17
Allowance for doubtful accounts - end of the year	2,338	2,954

The allowance for doubtful accounts was determined considering mitigation factors of the counterparty risk amounting to €3,493 million (€5,744 million at December 31, 2022), which included escrow accounts, insurance policies, sureties and bank guarantees.

Additions to allowance for doubtful accounts for trade and other performing receivables related to: (i) the Plenitude business line for €78 million (€61 million in 2022), mainly in the retail business; (ii) the Global Gas & LNG Portfolio segment for €23 million (€70 million in 2022), concerning business customers.

Additions to allowance for doubtful accounts for trade and other defaulted receivables related to: (i) the Exploration & Production segment for €238 million (€122 million in 2022) 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) to the Plenitude business line for €90 million (€99 million in 2022), particularly in the retail business.

Utilizations of allowance for doubtful accounts for trade and other performing and defaulted receivables amounted to €625 million and mainly related to: (i) to the Global Gas & LNG Portfolio segment for €160 million as consequence of the reduction in credit exposures due to the changed market conditions; (ii) the Plenitude business line for €182 million, in particular utilizations against charges of €126 million; (iii) the Exploration & Production segment for €90 million, of which €59 million for unused provisions following the in-kind reimbursements of the overdue receivables owed to Eni by the state-owned company PDVSA in Venezuela during the year.

Other changes included €662 million related to the reclassification to assets held for sale of the allowance for doubtful accounts relating to the subsidiary Nigerian Agip Oil Company Ltd.

Net (impairments) reversals of trade and other receivables are disclosed as follows:

(€ million)	2023	2022	2021
New provisions	(502)	(419)	(550)
Net credit losses	(98)	(81)	(66)
Reversals	351	547	337
Net (impairments) reversals of trade and other receivables	(249)	47	(279)

Receivables with related parties are disclosed in note 36 – Transactions with related parties.

9 Current and non-current inventories

Current inventories are disclosed as follows:

	December	December
(€ million)	31, 2023	31, 2022
Raw and auxiliary materials and consumables	1,292	1,228
Components and spare parts for drilling operations, plans and equipment	1,628	1,515
Semi-finished, finished products and goods	3,260	4,962
Other	6	4
Current inventories	6,186	7,709

Raw and auxiliary materials and consumables include oil-based feedstock and other consumables pertaining to refining and chemical activities.

Components to be consumed in drilling activities and spare parts of the Exploration & Production segment amounted to €1,490 million (€1,387 million at December 31, 2022).

Semi-finished, finished products and goods included natural gas and oil products for €2,376 million (€3,818 million at December 31, 2022) and chemical products for €666 million (€790 million at December 31, 2022).

Inventories are stated net of write-down provisions of €583 million (€672 million at December 31, 2022).

Non-current inventories of €1,576 million (€1,786 million at December 31, 2022) are held for compliance purposes and related to Italian subsidiaries for €1,555 million (€1,764 million at December 31, 2022) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.

The decrease in current and non-current inventories was essentially due to the decline in oil and hydrocarbons prices.

10 Income tax receivables and payables

(€ million)	December 31, 2023				December 31, 2022
	Receivables		Payables		Receivables		Payables
		Non		Non		Non		Non
	Current	current	Current	current	Current	current	Current	current
Income taxes	460	142	1,685	38	317	114	2,108	253

Income taxes are described in note 33 — Income taxes.

Current income tax payables include a portion of €455 million relating to the one-off Solidarity Contribution for 2023, enacted by Budget Law 2023, the payment of which was deferred to 2024 as a result of regulatory provisions.

Non-current income tax payables include 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 €33 million (€206 million at December 31, 2022).

11 Other assets and liabilities

	December 31, 2023				December 31, 2022
(€ million)	Assets		Liabilities		Assets		Liabilities
	Current	Non current	Current	Non current	Current	Non current	Current	Non current
Fair value of derivative
financial instruments	3,323	46	2,414	153	11,076	129	9,042	286
Contract liabilities			437	691			1,145	706
Other Taxes	915	137	1,811	16	807	157	1,463	34
Other	1,399	3,210	917	3,236	938	1,950	823	2,208
	5,637	3,393	5,579	4,096	12,821	2,236	12,473	3,234

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 €755 million, of which €637 million are current, and advances made in December (€569 million at December 31, 2022, of which €432 million current).

Other assets included: (i) tax credits current of €812 million (€366 million at December 31, 2022) and non-current of €2,247 million (€903 million at December 31, 2022) deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings; (ii) gas volumes prepayments that were made in previous years due to the take-or-pay obligations in relation to the Company's long-term supply contracts, whose underlying current portion Eni plans to recover beyond 12 months for €307 million (within 12 months for €41 million and beyond 12 months for €357 million at December 31, 2022); (iii) underlifting positions of the Exploration & Production segment of €295 million (€239 million at December 31, 2022); (iv) non-current receivables from divestment activities for €205 million (€23 million at December 31, 2022).

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 €469 million (€430 million at December 31, 2022); (ii) prepaid electronic fuel vouchers for €292 million (€338 million at December 31, 2022); (iii) advances received from Engie SA (former Suez) relating to a long-term agreement for supplying natural gas and electricity. The current portion amounted to €56 million (€58 million at December 31, 2022), the non-current portion amounted to €275 million (€333 million at December 31, 2022); (iv) advances received from customers for future gas supplies for €10 million (€538 million at December 31, 2022).

Revenues recognized during the year related to contract liabilities stated at December 31, 2023 are indicated in note 29– Revenues and other income.

Liabilities related to other current taxes include excise duties and consumer taxes for €1,034 million (€613 million at December 31, 2022) and VAT liabilities for €326 million (€332 million at December 31, 2022).

Other liabilities included: (i) non-current payables to factoring companies connected with the derecognition of the abovementioned tax credit deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings for €2,040 million (€758 million at December 31, 2022); (ii) 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 €391 million (€443 million at December 31, 2022), of which the underlying volumes are expected to be drawn within the next 12 months for €131 million (€85 million at December 31, 2022); (iii) prepaid revenues and deferred income of which current for €134 million (€104 million at December 31, 2022); (iv) current overlifting imbalances of the Exploration & Production segment for €312 million (€479 million at December 31, 2022); (v) non-current cautionary deposits for €286 million (€305 million at December 31, 2022), of which €213 million from retail customers for the supply of gas and electricity (€222 million at December 31, 2022); (vi) payables related to investing activities for €101 million (€83 million at December 31, 2022).

Transactions with related parties are described in note 36 — Transactions with related parties. ## 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
2023
Net carrying amount - beginning of
the year	1,088	40,492	4,280	1,345	7,494	1,633	56,332
Additions	22		407	764	6,294	1,252	8,739
Depreciation capitalized				20	184	1	205
Depreciation (*)	(47)	(5,699)	(610)				(6,356)
Impairments	(30)	(1,164)	(366)		(226)	(390)	(2,176)
Reversals		109	42		257	36	444
Write-off			(2)	(420)	(25)		(447)
Currency translation differences	1	(1,223)	(39)	(46)	(268)	(3)	(1,578)
Initial recognition and changes in
estimates	3	698	16	17	14		748
Changes in the scope of consolidation -
included entities	48	521	298		131	77	1,075
Changes in the scope of consolidation -
excluded entities			(1)				(1)
Transfers	37	5,592	595	(70)	(5,522)	(632)
Other changes	(11)	(1,905)	(32)	(42)	1,349	(45)	(686)
Net carrying amount - end of the
year	1,111	37,421	4,588	1,568	9,682	1,929	56,299
Gross carrying amount - end of the
year	4,354	139,866	32,121	1,568	13,670	4,308	195,887
Provisions for depreciation and
impairments	3,243	102,445	27,533		3,988	2,379	139,588
2022
Net carrying amount - beginning of
the year	1,071	42,342	3,850	1,244	6,497	1,295	56,299
Additions	22	132	456	655	5,361	1,074	7,700
Depreciation capitalized				11	179		190
Depreciation (*)	(51)	(5,466)	(555)				(6,072)
Impairments	(21)	(313)	(485)		(149)	(414)	(1,382)
Reversals	3	40	191		141	38	413
Write-off	(1)		(2)	(365)	(218)		(586)
Currency translation differences	2	2,422	55	74	368	5	2,926
Initial recognition and changes in
estimates		(173)	2	(7)	98		(80)
Changes in the scope of consolidation -
included entities	9	650	695			118	1,472
Changes in the scope of consolidation -
excluded entities	(1)	(3,687)	(6)	(119)	(546)		(4,359)
Transfers	41	4,402	426	(149)	(4,253)	(467)
Other changes	14	143	(347)	1	16	(16)	(189)
Net carrying amount - end of the
year Gross carrying amount - end of the	1,088	40,492	4,280	1,345	7,494	1,633	56,332
year	4,255	143,432	31,328	1,345	11,654	3,798	195,812
Provisions for depreciation and
impairments	3,167	102,940	27,048		4,160	2,165	139,480

(*) Before capitalization of depreciation of tangible assets

Capital expenditures included capitalized finance expenses of €94 million (€38 million in 2022) related to the Exploration & Production segment for €64 million (€22 million in 2022) at an average interest rate of 3.0% (2.1% at December 31, 2022).

Capital expenditures primarily related to the Exploration & Production segment for €7,105 million (€6,185 million in 2022).

The line item "Other changes" (€966 million) included expenditures to purchase plants and equipment from suppliers, with whom delayed payment terms were agreed and were reclassified in the balance sheet to financing payables.

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.

The main depreciation rates adopted are included in the following ranges and have remained unchanged compared to 2022:

(%)
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 in the extraction and treatment of hydrocarbons were depreciated according to the UOP method, where depreciation depends on production of the estimated proved reserves according to the US Securities & Exchange Commission "SEC" criteria (see note 1 – Accounting standards, accounting estimates and significant judgements, section UOP depreciation, depletion and amortisation). The production plans associated with the existing assets gradually deplete the SEC proved reserves recorded at the balance sheet date, which are expected to be produced within about ten years.

Asset net impairment losses of property, plant and equipment related to: (i) oil&gas properties (€1,025 million) due to negative reserve revisions at assets in Alaska, Gulf of Mexico, Turkmenistan and Australia, and because of the projections of lower natural gas prices which negatively affected the expected cash flows of assets in Italy, net of recovery in value of an oil field in Congo; (ii) expenditures incurred for compliance and stay-in-business at CGUs in the refining sector, which were impaired in previous reporting periods and continued lacking any profitability prospects (€345 million); (iii) petrochemical plants for production of intermediates, styrenics and, to a lesser extent, elastomers due to lower future expected cash flows driven by a deteriorated industry outlook (€367 million). More information about Eni's impairment review and the sensitivity of the outcome to different commodities scenarios is reported in note 15 – Reversals (Impairments) of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonisation scenarios.

Currency translation differences related to subsidiaries utilizing the U.S. dollar as functional currency (€1,572 million).

Initial recognition and change in estimates includes the increase in the asset retirement cost of tangible assets in the Exploration & Production segment due to the increase in abandonment cost estimates, start of new projects and the decrease in discount rates.

Changes in the scope of consolidation related: (i) for €548 million to the acquisition of BP business in Algeria, including the two gas-producing concessions "In Amenas" (Eni In Amenas Ltd) and "In Salah" (Eni In Salah Ltd) jointly operated with Sonatrach and Equinor; (ii) for €255 million the acquisition of control of Novamont, already owned by Eni with 36% interest, operating in the production of bioplastics; (iii) for €168 million to the acquisitions of renewables activities in the Plenitude business line, particularly the two Spanish companies HLS Bonete PV SLU and HLS Bonete Topco SLU; (iv) for €104 million the acquisition from Chevron of the companies now renamed as Eni Ganal Deepwater Ltd and Eni Rapak Deepwater Ltd which hold a 62% share, respectively, in the Ganal and Rapak blocks already owned with a 20% interest by Eni in addition to the company now renamed as Eni Makassar Ltd which holds a 72% share in Makassar block.

Other changes included the reclassification to assets held for sale of the onshore Nigerian assets relating to the sale agreement with the company Oando PLC for €914 million and other oil permits in Congo for €355 million.

Transfers from E&P tangible assets in progress to E&P UOP wells, plant and equipment related for €5,355 million to the commissioning of wells, plants and machinery primarily in Ivory Coast, Italy, Congo, Egypt, Iraq, Mexico, United States and Algeria.

In 2023, exploration and appraisal activities decreased by €420 million due to the write-offs of the capitalized costs of exploration wells pending economic and technical evaluation in Egypt, Mexico, Mozambique, Morocco, United Arab Emirates and Lebanon.

Exploration and appraisal activities related for €1,391 million to the costs of suspended exploration wells pending final determination of commerciality based on management's continuing commitment and for €177 million to costs of exploration wells in progress at the end of the year.

Changes relating to suspended wells are reported below:

(€ million)	2023	2022	2021
Costs for exploratory wells suspended - beginning of the year	1,085	1,101	1,268
Increases for which is ongoing the determination of proved reserves	834	547	288
Amounts previously capitalized and expensed in the year	(388)	(374)	(286)
Reclassification to successful exploratory wells following the estimation of proved
reserves	(72)	(147)	(43)
Disposals	(3)	(2)	(3)
Changes in the scope of consolidation		(114)	(199)
Currency translation differences	(40)	65	100
Other changes	(25)	9	(24)
Costs for exploratory wells suspended - end of the year	1,391	1,085	1,101

The following information relates to the stratification of the suspended wells pending final determination (ageing):

	2023		2022		2021
		(number of wells in Eni's		(number of wells in Eni's		(number of wells in Eni's
Costs capitalized and suspended	(€ million)	interest)	(€ million)	interest)	(€ million)	interest)
for exploratory well activity
- within 1 year	417	7.9	216	5.0	175	4.0
- between 1 and 3 years	347	6.1	246	4.9	269	12.2
- beyond 3 years	627	14.5	623	13.9	657	19.7
	1,391	28.5	1,085	23.8	1,101	35.9
Costs capitalized for suspended
wells
- fields including wells drilled over
the last 12 months	417	7.9	204	4.5	175	4.0
- fields for which the delineation
campaign is in progress	804	14.0	579	11.3	567	17.9
- fields including commercial
discoveries that are progressing to
a FID	170	6.6	302	8.0	359	14.0
	1,391	28.5	1,085	23.8	1,101	35.9

Suspended wells costs awaiting a final investment decision amounted to €170 million and primarily related to initiatives in the main countries of presence (Egypt, Nigeria and Congo).

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	Turkmenistan	USA	Algeria	Egypt	United Arab Emirates	Italy	Indonesia	Total
2023
Carrying amount -
beginning of the year	198	958	95	16	211	3	520	2		2,003
Additions					61				92	153
Net (impairments) reversals	243		(93)	8						158
Reclassification to Proved
Mineral Interest		(1)			(51)	(1)	(28)			(81)
Currency translation
differences and other
changes	(12)	(33)	(2)	(1)	(6)		(17)		(3)	(74)
Carrying amount - end of
the year	429	924		23	215	2	475	2	89	2,159
2022
Carrying amount -
beginning of the year	218	892	3	68	114	16	508			1,819
Additions		11			110	(2)		2		121
Net (impairments) reversals	(28)		93	(56)						9
Reclassification to Proved
Mineral Interest	(6)				(19)	(12)	(19)			(56)
Currency translation
differences and other
changes	14	55	(1)	4	6	1	31			110
Carrying amount - end of
the year	198	958	95	16	211	3	520	2		2,003

Unproved mineral interests comprised the Oil Prospecting License 245 property ("OPL 245"), offshore Nigeria, whose exploration period expired on May 11, 2021. The property book value included €888 million corresponding to the price paid in 2011 to the Nigerian Government to acquire a 50% interest in the asset, plus the subsequent capitalized exploration costs and pre-development costs bringing the total net book value to €1,208 million. A lengthy and complex criminal proceeding before the Court of Milan was definitively resolved during 2022 in favor of Eni, which related to alleged crimes of international corruption regarding the acquisition of the license, whereas in 2023 the Federal Republic of Nigeria renounced to continue a claim to obtain compensation for the alleged damages (see note 28 – Guarantees, Commitments and Risks – Legal proceedings). The request for conversion of the license into an Oil Mining Lease (OML) before the relevant Nigerian authorities to start the development of the reserves is still pending. Given the inaction of the Nigerian authorities, a few years ago Eni started an arbitration proceeding before an ICSID tribunal, the International Centre for Settlement of Investment Disputes, to preserve the value of the investment. Regardless of the outcome of the ongoing arbitration, the estimate of the asset value in the perspective of its economic utilization confirmed the recoverability of the asset's book value by discounting the expected cash flows at the country WACC (8%).

Accumulated provisions for impairments amounted to €22,650 million (€21,715 million at December 31, 2022).

Property, plant and equipment includes assets subject to operating leases for €347 million, essentially relating to service stations of the Enilive and Refining business line.

As of December 31, 2023, Eni pledged property, plant and equipment for €24 million to guarantee payments of excise duties (same amount as of December 31, 2022).

Government grants recorded as a decrease of property, plant and equipment amounted to €91 million (€115 million at December 31, 2022).

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.

13 Right-of-use assets and lease liabilities

	Floating production storage and offloading vessels	Drilling	Naval facilities and related logistic bases for oil and gas	Motorway concessions and service	Oil and gas distribution	Office
(€ million) 2023	(FPSO)	rig	transportation	stations	facilities	buildings Vehicles		Other	Total
Net carrying amount -
beginning of the year	2,142	148	682	457	19	595	42	361	4,446
Additions	14	570	402	133	19	110	14	322	1,584
Depreciation(a)	(145)	(219)	(315)	(74)	(18)	(125)	(12)	(65)	(973)
Impairments			(3)		(2)			(36)	(41)
Reversals			3					2	5
Currency translation
differences	(71)	(8)	(5)	4		(2)		(7)	(89)
Changes in the scope of
consolidation						3		10	13
Other changes	37	(42)	(40)	(28)	(1)	(1)	(27)	(9)	(111)
Net carrying amount -
end of the year	1,977	449	724	492	17	580	17	578	4,834
Gross carrying amount - end of the year	2,409	985	1,593	822	81	1,039	47	826	7,802
Provisions for
depreciation and
impairment	432	536	869	330	64	459	30	248	2,968
2022
Net carrying amount -
beginning of the year	2,667	183	575	454	14	618	48	262	4,821
Additions	1,342	189	530	76	28	108	21	110	2,404
Depreciation (a)	(226)	(197)	(303)	(70)	(13)	(130)	(21)		(53) (1,013)
Impairments			(5)		(5)		(1)	(7)	(18)
Reversals			14						14
Currency translation differences	239	12	10	3		3			267
Changes in the scope of
consolidation	(1,878)	(34)	(39)			(1)		73	(1,879)
Other changes	(2)	(5)	(100)	(6)	(5)	(3)	(5)	(24)	(150)
Net carrying amount -
end of the year	2,142	148	682	457	19	595	42	361	4,446
Gross carrying amount -
end of the year	2,507	516	1,360	734	87	1,010	86	562	6,862
Provisions for depreciation and
impairment	365	368	678	277	68	415	44	201	2,416

(a) Before capitalization of depreciation of tangible assets

Right-of-use assets (RoU) of €4,834 million related: (i) for €2,959 million (€2,653 million at December 31, 2022) to the Exploration & Production segment and mainly comprised leases of certain FPSO vessels hired in connection with operations at offshore development projects in Ghana (OCTP) and Area 1 in Mexico with an expected term ranging between 13 and 17 years, including a renewal option as well as multi-year leases of offshore drilling rigs; (ii) for €965 million (€800 million at December 31, 2022) to the Enilive, Refining and Chemicals segment relating to highways concessions to market fuels, land leases, leases of service stations for the sale of oil products, leasing of vessels for shipping activities and the car fleet dedicated to the car sharing business; (iii) for €519 million (€548 million at December 31, 2022) to the Corporate and Other activities segment mainly regarding property rental contracts.

The increase recorded in 2023 mainly referred to: (i) the Exploration & Production segment for €1,023 million relating to rental of drilling rigs (€570 million) and vessels and related logistics equipments for Oil & Gas transport (€167 million); (ii) the Enilive and Refining business line for €408 million, relating in particular to lease of vessels for shipping and storage activities of Eni Trade & Biofuels SpA (€220 million), new contracts and extension of existing contracts relating motorway concessions, land leases, service station leases and the car fleet dedicated to the car sharing business (€146 million); (iii) to the Corporate and Other activities segment for €63 million relating in particular to leasing of assets for staff activities (€44 million).

The main leasing contracts signed for which the asset is not yet available concern: (i) a contract with a nominal value of €437 million relating to leasing of office buildings with an expiry date of 20 years including an extension option of 6 years; (ii) storage capacity and time charter vessels rental contracts of €131 million.

Main future cash outflows potentially due not reflected in the measurements of lease liabilities related to: (i) options for the extension or termination of lease for office buildings of €1,177 million; (ii) extension options related to ancillary assets in the upstream business for €545 million; (iii) extension options related to service stations for the sale of oil products of €133 million.

Liabilities for leased assets were as follows:

(€ million)	Current portion of long-term lease liabilities	Long-term lease liabilities	Total
2023
Carrying amount at the beginning of the year	884	4,067	4,951
Additions		1,584	1,584
Decreases	(949)	(14)	(963)
Currency translation differences	(16)	(81)	(97)
Changes in the scope of consolidation	1	12	13
Other changes	1,208	(1,360)	(152)
Carrying amount at the end of the year	1,128	4,208	5,336
2022
Carrying amount at the beginning of the year	948	4,389	5,337
Additions		2,401	2,401
Decreases	(980)	(14)	(994)
Currency translation differences	43	242	285
Changes in the scope of consolidation	(299)	(1,654)	(1,953)
Other changes	1,172	(1,297)	(125)
Carrying amount at the end of the year	884	4,067	4,951

Lease liabilities related for €480 million (€494 million at December 31, 2022) to the portion of the liabilities attributable to joint operators in Eni-led projects which will be recovered through the mechanism of the cash calls.

Total cash outflows for leases consisted of the following: (i) cash payments for the principal portion of the lease liability for €963 million; (ii) cash payments for the interest portion of €255 million.

Lease liabilities stated in U.S. dollars and euro amounted to €3,573 million and €1,608 million, 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 consist of the following:

(€ million)	2023	2022	2021
Other income and revenues
Income from remeasurement of lease liabilities	17	6	18
	17	6	18
Purchases, services and other
Short-term leases	59	113	85
Low-value leases	37	27	31
Variable lease payments not included in the measurement of lease liabilities	20	14	14
Capitalized direct cost associated with self-constructed assets - tangible
assets	(5)	(5)	(4)
	111	149	126
Depreciation and impairments
Depreciation of RoU leased assets	973	1,013	928
Capitalized amortization of RoU leased assets - tangible assets	(199)	(186)	(110)
Impairments of RoU leased assets	41	18	59
Reversals of RoU leased assets	(5)	(14)
	810	831	877
Finance income (expense) from leases
Interests on lease liabilities	(267)	(315)	(304)
Capitalized finance expense of RoU leased assets - tangible assets	11	8	5
Net currency translation differences on lease liabilities	19	(4)	(34)
	(237)	(311)	(333)

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
2023
Net carrying amount - beginning of
the year Additions	793 20	176 41	1,394 415	2,363 476	3,138	24	5,525 476
Amortization	(8)	(92)	(255)	(355)			(355)
Impairments	(22)		(17)	(39)	(6)		(45)
Reversals	11			11			11
Write-off	(85)		(3)	(88)			(88)
Changes in the scope of consolidation		291	461	752	25	2	779
Currency translation differences	(19)		(1)	(20)			(20)
Other changes	(27)	34	113	120	(24)		96
Net carrying amount - end of the year	663	450	2,107	3,220	3,133	26	6,379
Gross carrying amount - end of the
year	1,295	2,119	4,674	8,088
Provisions for amortization and
impairment	632	1,669	2,567	4,868
2022
Net carrying amount - beginning of
the year	913	155	845	1,913	2,862	24	4,799
Additions	53	28	275	356			356
Amortization	(12)	(74)	(224)	(310)			(310)
Impairments			(14)	(14)	(153)		(167)
Write-off	(13)			(13)			(13)
Changes in the scope of consolidation	(200)		391	191	482		673
Currency translation differences	54		1	55	11		66
Other changes	(2)	67	120	185	(64)		121
Net carrying amount - end of the year	793	176	1,394	2,363	3,138	24	5,525
Gross carrying amount - end of the
year	1,428	1,806	3,705	6,939
Provisions for amortization and
impairment	635	1,630	2,311	4,576

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 in Egypt.

The breakdown of exploration rights by type of asset was as follows:

(€ million)	December 31, 2023	December 31, 2022
Proved licence and leasehold property acquisition costs	91	104
Unproved licence and leasehold property acquisition costs	572	689
	663	793

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 €85 million related to the abandonment of underlying initiatives.

Changes in the scope of consolidation of assets with a finite useful life concerned: (i) for €515 million the acquisition of control of Novamont group; (ii) for €237 million the acquisitions finalized by Plenitude in relation to renewables activities, in particular Spanish companies.

Other changes relating to intangible assets with a finite useful life related: (i) for €58 million to the definitive price allocation of acquisitions made in 2022 (further information is provided in note 27 - Other information); (ii) for €25 million the decrease relating to the reclassification to assets held for sale of unproved potential and exploration rights of the company Nigerian Agip Oil Co Ltd (further information is disclosed in note 25 - Assets held for sale and liabilities directly associated with assets held for sale).

Other intangible assets comprised: (i) concessions, licenses, trademarks and similar items for €1,148 million (€692 million at December 31, 2022), of which €879 million relating to relating to the Plenitude business line essentially for activities in relation to renewable energy sources; (ii) customer acquisition costs relating to the Plenitude business line for €393 million (€358 million at December 31, 2022); (iii) customer relationship for €92 million recognized following the acquisition of Finproject group (€101 million at December 31, 2022).

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 €2,656 million.

The breakdown of goodwill by segment and business line is provided below:

(€ million)	December 31, 2023	December 31, 2022
Plenitude	2,909	2,927
Enilive and Refining	102	102
Chemicals	112	93
Corporate and Other activities	10	16
	3,133	3,138

Changes in the scope of consolidation of goodwill related to: (i) the acquisition of control of Novamont group for €19 million; (ii) acquisitions in relation to renewables activities of the Plenitude business line for €6 million.

Other negative changes relating to goodwill of €24 million concerned the definitive allocation of some acquisitions made in 2022 whose price allocation was carried out on a provisional basis (further information is provided in note 27 – Other information).

Contributions recorded as decrease of intangible assets amounted to €28 million.

Information about the allocations of goodwill deriving from business combinations is provided in note 5 – Business combinations and other significant transactions.

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 network of recharges for electric vehicles. Plenitude has closed several acquisitions in past reporting years and in 2023, those latter commented in note 5 – Business combinations and other significant transactions, 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 €1,215 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.

The impairment review of the CGU Retail²⁷, 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 four-year 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, riskadjusted WACCs of the retail business in each country of operation, with values in a range of approximately 5%. There are no reasonable assumptions of changes in the discount rate, growth rate, profitability or volumes that would lead to zeroing the headroom amounting to about €6.4 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 €976 million related to the business combinations made in Italy and in other European markets where operations are being developed (Spain, France, Greece) in 2023 and past years. To test its recoverability, the activities were grouped by homogeneous CGUs, corresponding to geographical areas, with regard to technical, economic and contractual matters. The recoverability of the goodwill was assessed with reference to the entire CGU. The cash flows include those obtainable from assets under operations and the repowering of existing plants and facilities. The recoverability test of the book values of renewable assets including the allocated goodwill was performed based on the discounted cash flows which comprised the financial projections of the four-year industrial plan approved by the management and the subsequent cash flows associated with the useful lives of the plants by using normalized cash flows. Cash flows have been discounted at sector and country-specific WACCs, which were comprised in a range of 5.5% - 6.1%. 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 €130 million is reduced to zero in case of a 0.3 percentage point increase in the WACC, or a reduction in power prices of approximately 4%.

Goodwill of the electric mobility business of Plenitude of €718 million recognized in connection with the acquisition in 2021 of the entire share capital of Be Power SpA, which through the subsidiary Be Charge is the second Italian operator in the segment of charging infrastructures for electric mobility, was assessed by updating the valuation model of the operation. The recoverability of the allocated goodwill was tested based on the discounted cash flows of the activity, which comprised the financial projections of the four-year industrial plan approved by management and subsequently the perpetuity of the final year of the plan assuming a growth rate of 4.6% that reflects trend forecasts in sales of electric vehicles, discounted at a WACC of 10.8%. This test confirmed the recoverability of the allocated goodwill and showed a headroom of about €400 million which would go to zero under no reasonable assumption.

²⁷Within the Retail CGU, the impairment test to verify the recoverability of the book values of the 1st level Plenitude Energy Services CGU was performed on the basis of the discounted cash flow method to 2050 which includes for the first four years projection of the business plan approved by management.

15 Reversals (Impairments) of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonisation scenarios

The recoverability test of carrying amounts of oil&gas cash generating units (CGUs) is the most important of the critical accounting estimates in the preparation of Eni's consolidated financial statements. This owes to the relative weight of the invested capital in the sector on total consolidated assets.

Future expected cash flows associated with the use of oil&gas assets are based on management's judgment and subjective evaluation about highly uncertain matters like future hydrocarbons prices, assets' useful lives, projections of future operating and capital expenditures, including CO² emission costs relating to geographies where legal obligations are present, the volumes of reserves that will ultimately be recovered and costs of decommissioning oil&gas assets at the end of their useful lives.

The hydrocarbon prices are forecasted as part of Eni's scenario, which considers macroeconomic and industry projections, policies, regulations, and technologies (in place or foreseeable) and providing a holistic and consistent framework for the economic and energy variables of interest. These forecasts incorporate management's best estimate of the various energy market fundamentals while considering the changing market environment and challenges related to the energy transition. Eni's scenario is constantly benchmarked against the market view of investment banks and energy consultants.

Below are the main price assumptions for assessing the recoverability of oil&gas assets, expressed in 2022 real terms for comparability with the IEA scenario:

	2024	2027	2030	2040	2050
Brent \$/bbl	73	68	68	58	48
TTF natural gas price \$/mmBtu	8.7	9.9	6.8	6.8	6.2

This scenario does not differ significantly from the one adopted in the previous reporting year, with the exception of forecasts of lower natural gas prices in the short term. Actual hydrocarbons prices utilized in the calculation of future revenues of oil&gas assets in the impairment review are derived from the main market benchmarks by applying appropriate price differentials, which were estimated by the management to consider factors like crude qualities, different indexation mechanisms and regional price trends.

The discount rate of the future cash flows of the CGUs was estimated as the weighted average cost of equity (Ke) and net borrowings, based on the Capital Asset Pricing Model methodology. Specifically, the cost of equity considers both a premium for the non-diversifiable market risk measured on the basis of the long-term returns of the S&P500, and an additional premium that considers exposure to operational risks of the countries of activity and the risks of the energy transition. For 2023, a Group cost of capital ("WAAC") of approximately 7% was estimated and was substantially unchanged compared to 2022 due to a lower cost of equity as a consequence of the reduction in the company's financial risk, which offset the increased yields on risk-free assets. The Group WACC is adjusted to account for the specific operational risks of each geography against the average portfolio, where oil&gas activities are conducted, by adding a corrective factor (WACC adjusted on a country-bycountry basis).

The impairment test was performed at all of the Group's oil&gas CGUs based on the price scenario of management and the country WACCs described above, which substantially confirmed the carrying amounts of the properties, with the exception of some assets which were marked to their lower recoverable values due to downward reserves revisions and expected reductions in natural gas prices, recognizing approximately €1 billion of net impairment losses. The geographical areas involved were mainly Alaska, Gulf of Mexico, Turkmenistan and Australia in relation to reserves revisions and gas assets in Italy in relation to gas prices. The post-tax discount rates were comprised in a range 6.0% - 7.5%; the pre-tax discount rates for the main net impairment losses were set to 5.1% in Italy and 20.3% in Alaska.

The value in use (VIU) of the oil&gas CGUs under the management's scenario assumptions displayed a headroom (difference between VIU and book values) of approximately 80% of the assets' carrying amounts, discounting the expected expenses associated with the purchase of carbon credits as part of the Company's strategy to decarbonize its oil&gas operations also through nature-based solutions of carbon offsets. Those sensitivity analyses included assets of all consolidated entities, joint ventures and associates, excluding Vår Energi ASA and Azule Energy Holdings Ltd. Considering the judgemental nature of the assumptions underlying the estimate of the VIU, management has stress-tested its base case by applying the following sensitivity analyses to the assumptions underlying the oil&gas CGUs values-in-use of the base case: (i) a 10% haircut to hydrocarbon prices applied to all the years of the cash flow projections; (ii) a one-percentage point increase in the risk-adjusted WACCs applied to each country of operations; (iii) the projections of hydrocarbon prices and CO2 costs of the decarbonization scenario Net Zero Emission 2050 (NZE 2050) elaborated by IEA. The values-in-use of oil&gas assets calculated under the different stress-test scenarios exhibit in their entirety a headroom over the assets book values; however it is possible the incurrence of impairment losses as shown in the table below.

The results of those sensitivity tests expressed in terms of percentage ratio of the cumulated headroom of the oil&gas CGUs to their corresponding book values under each scenario and potential pre-tax income statement impacts are provided below:

	Value in use of the O&G CGUs Headroom vs Carrying amounts		Possible impairments	Assumption at 2050 in real terms USD 2022
	Tax deductible C O2 charges	Non tax deductible C O2 charges	€ billion	Brent price	European gas price	Cost of C O2
Eni's scenario	77%	-		48 \$/bbl	6.2 \$/mmBTU	CO2 costs projections in the EU/ETS + projections of forestry costs
10% haircut of Eni's prices assumptions	56%	-	(1.0)			CO2 costs projections in the EU/ETS + projections of forestry costs
Eni's scenario with +1% increase in WAAC	67%	-	(0.2)			CO2 costs projections in the EU/ETS + projections of forestry costs
IEA NZE 2050 scenario	28%	23%	(3.2) - (4.3)	25 \$/bbl	4.1 \$/mmBTU	250-180\$ per tonne of (*) CO2

(*) Range of values depending on advanced or emerging economies with or without net zero commitments. For low-income economies a lower cost is expected.

These sensitivities do not consider possible actions to mitigate a changed price environment, such as rescheduling and/or cancellation of planned development activities, contractual renegotiations, costs efficiencies or actions aimed at accelerating the pay-back period.

Sensitivity was not applied to Chemicals and Gas power generation business lines considering the immateriality of the residual book values of property, plant and equipment (€581 million and €766 million, respectively) and of economic-technical lives, while no impact can be associated for refineries considering that their book values are zero.

16 Investments

Equity-accounted investments

	2023				2022
	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	50	7,065	4,977	12,092	44	2,057	3,786	5,887
Additions and
subscriptions	3	1,024	186	1,213	21	900	686	1,607
Divestments and
reimbursements					(2)	(1)	(477)	(480)
Share of profit of equity
accounted investments	4	818	800	1,622	5	474	1,684	2,163
Share of loss of equity
accounted investments	(3)	(149)	(129)	(281)	(6)	(197)	(82)	(285)
Deduction for dividends	(1)	(939)	(1,060)	(2,000)	(3)	(483)	(708)	(1,194)
Changes in the scope of
consolidation	3	13	(227)	(211)	5	(710)	(1,122)	(1,827)
Currency translation
differences	(2)	(244)	(166)	(412)	2	(231)	230	1
Other changes	(1)	662	(54)	607	(16)	5,256	980	6,220
Carrying amount - end
of the year	53	8,250	4,327	12,630	50	7,065	4,977	12,092

Acquisitions and share capital increases mainly related: (i) for €882 million to the acquisition from PBF Energy Inc of 50% of the capital of St. Bernard Renewables Llc, an operating biorefinery at Chalmette hub in Louisiana (United States of America), whose production started in the second half of the 2023. The price allocation to the net assets acquired was carried out on a provisional basis, with the recognition of goodwill of €45 million; (ii) for €154 million to the capital subscription of QatarEnergy LNG NFE (5) (former Qatar Liquefied Gas Company Limited (9)) (Eni's interest 25%), a company participating in the North Field East (NFE) project with a 12.5% interest, equal to an Eni's interest of 3.125% in the giant project for the development of the country's LNG; (iii) for €42 million to the subscription of the capital increase of Vårgrønn AS, the joint venture (Eni's interest 65%) which owns the 20% stake in the Doggerbank A, B and C offshore wind projects in the United Kingdom.

Share of profit from equity-accounted investments essentially referred to: (i) Azule Energy Holdings Ltd for €653 million; (ii) Vår Energi ASA for €356 million; (iii) Abu Dhabi Oil Refining Company (TAKREER) for €296 million; (iv) ADNOC Global Trading Ltd for €120 million; (v) Saipem SpA for €56 million; (vi) SeaCorridor Srl for €49 million; (vii) Mozambique Rovuma Venture SpA for €47 million.

Share of loss from equity-accounted investments essentially referred to: (i) Vårgrønn AS for €50 million; (ii) St. Bernard Renewables Llc for €42 million; (iii) Coral FLNG SA for €40 million.

Reduction for dividends related to: (i) Azule Energy Holdings Ltd for €829 million; (ii) Vår Energi ASA for €640 million; (iii) Abu Dhabi Oil Refining Company (TAKREER) for €277 million; (iv) ADNOC Global Trading Ltd for €129 million; (v) SeaCorridor Srl for €95 million.

Changes in the scope of consolidation referred for €227 million to the acquisition of the control of Novamont Business combinations are commented in note 5 - Business combinations and other significant transactions.

Other changes included the initial recognition of the joint venture SeaCorridor Srl (Eni's interest 50.1%) for €580 million, €414 million higher than the book value of the corresponding company share maintained, following the business combination which involved the sale to Snam of 49.9% interest of the Eni's companies operating natural gas transportation from Algeria through the TTPC and TMPC pipelines.

Net carrying amounts related to the following companies:

	December 31, 2023		December 31, 2022
	Net		Net
(€ million)	carrying amount	% of the investment	carrying amount	% of the investment
Investments in unconsolidated entities controlled by Eni
Other	53		50
	53		50
Joint ventures
Azule Energy Holdings Ltd	4,750	50.00	5,073	50.00
St. Bernard Renewables Llc	829	50.00
Saipem SpA	722	31.20	645	31.20
SeaCorridor Srl	530	50.10
Cardón IV SA	443	50.00	433	50.00
Mozambique Rovuma Venture SpA	343	35.71	308	35.71
Vårgrønn AS	336	65.00	370	65.00
GreenIT SpA	92	51.00	74	51.00
Lotte Versalis Elastomers Co Ltd	43	50.00	41	50.00
Hergo Renewables SpA	32	65.00	33	65.00
LabAnalysis Environmental Scienze Srl	25	30.00
Società Oleodotti Meridionali - SOM SpA	21	70.00	29	70.00
Other	84		59
	8,250		7,065
Associates
Abu Dhabi Oil Refining Company (Takreer)	2,434	20.00	2,497	20.00
Vår Energi ASA	447	63.04	763	63.08
QatarEnergy LNG NFE (5)	439	25.00	302	25.00
Coral FLNG SA	239	25.00	330	25.00
ADNOC Global Trading Ltd	145	20.00	158	20.00
United Gas Derivatives Co	81	33.33	72	33.33
Novis Renewables Holdings Llc	70	49.00	74	49.00
Bluebell Solar Class A Holdings II Llc	70	99.00	73	99.00
Novamont SpA			255	35.00
Altre	402		453
	4,327		4,977
	12,630		12,092

The results of equity-accounted investments by segment are disclosed in note 35 – Segment information and information by geographical area.

As of December 31, 2023, the book and market values of Saipem SpA and Vår Energi ASA, equity-accounted companies listed on the Italian and the Norwegian stock exchange, respectively, were as follows:

	Saipem SpA	Vår Energi ASA
Number of shares held	662,476,192	1,573,713,749
% of the investment	31.20	63.04
Share price (€)	1.47000	2.86287
Market value (€ million)	915	4,505
Book value (€ million)	722	447

At December 31, 2023, the market capitalization of Saipem shares exceeded the book value of the investment by €193 million, the carrying amount is in line with the corresponding fraction of the investee's book equity, less the fraction of the investee net assets corresponding to the equity component of a convertible bond.

At December 31, 2023, the market capitalization of the Vår Energi ASA share for Eni's stake was €4,058 million higher than the book value of the investment.

Additional information is included in note 37 – Other information about investments.

Other investments

(€ million)	2023	2022
Carrying amount - beginning of the year	1,202	1,294
Additions and subscriptions	102	68
Change in the fair value with effect to OCI	45	56
Currency translation differences	(28)	42
Other changes	(65)	(258)
Carrying amount - end of the year	1,256	1,202

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-theparts 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 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 valuation.

Dividend income from these investments is disclosed in note 32 – Income (expense) from investments.

The investment book value as of December 31, 2023 primarily related to Nigeria LNG Ltd for €642 million (€668 million at December 31, 2022), Saudi European Petrochemical Co "IBN ZAHR" for €121 million (€108 million at December 31, 2022) and Darwin LNG Pty Ltd for €78 million (€71 million at December 31, 2022).

Table of Contents 17 Other financial assets

		December 31, 2023	December 31, 2022
(€ million)	Current	Non-current	Current	Non-current
Long-term financing receivables held for operating purposes	34	2,240	11	1,911
Short-term financing receivables held for operating purposes	7		8
	41	2,240	19	1,911
Financing receivables held for non-operating purposes	855		1,485
	896	2,240	1,504	1,911
Securities held for operating purposes		61		56
	896	2,301	1,504	1,967

Changes in allowance for doubtful accounts were as follows:

(€ million)	2023	2022
Carrying amount at the beginning of the year	391	403
Additions	15	13
Deductions	(9)	(43)
Currency translation differences	(13)	21
Other changes	(1)	(3)
Carrying amount at the end of the year	383	391

Financing receivables held for operating purposes primarily related to funds provided to joint ventures and associates in the Exploration & Production segment (€2,173 million) to execute capital projects of interest to Eni. These receivables are longterm interests in the initiatives funded. The main amounts were towards: (i) the joint venture Mozambique Rovuma Venture SpA (Eni's interest 35.71%) for €1,339 million (€1,187 million at December 31, 2022) engaged in the development of natural gas reserves of the Mamba in Area 4 offshore Mozambique; (ii) Coral FLNG SA (Eni's interest 25%) for €453 million (€356 million at December 31, 2022).

Financing receivables held for operating purposes due beyond five years amounted to €149 million (€164 million at December 31, 2022).

The fair value of non-current financing receivables held for operating purposes of €2,285 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from 1.9% to 5.2% (1.8% and 5.1% at December 31, 2022).

The recoverability of other long-term financial assets was assessed by considering the expected probability of default in the next twelve months only, as the creditworthiness suffered no significant deterioration in the reporting period.

Financing receivables held for non-operating purposes of €712 million (€1,266 million at December 31, 2022) related to restricted deposits in escrow to guarantee transactions on derivative contracts mainly in the Global Gas & LNG Portfolio segment.

Financing receivables were denominated in euro and U.S. dollar for €630 million and €2,503 million, respectively.

Securities for €19 million (€20 million at December 31, 2022) 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	19	19	17	from 0 to 2.65	from 2024 to 2031	Baa3	BBB
Others (*)	25	25	25	from 0.1 to 5.0	from 2024 to 2027	from Aa1 to Baa2	from AA+ to BBB
Floating rate bonds
Italy	12	12	12	from 4.62 to 5.07	from 2024 to 2026	Baa3	BBB
Total sovereign states	56	56	54
Other financial institutions
European Bank of					from 2023 to
Investments	5	5	5	3.98	2024	Aaa	AAA
Total	61	61	59

(*) Amounts included herein are lower than €10 million.

Securities having maturity within five years amounted to €55 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.

18 Trade and other payables

(€ million)	December 31, 2023	December 31, 2022
Trade payables	14,231	19,527
Down payments and advances from joint ventures in exploration & production activities	717	606
Payables for purchase of non-current assets	2,335	2,561
Payables due to partners in exploration & production activities	1,215	1,235
Other payables	2,156	1,780
	20,654	25,709

The decrease in trade payables of €5,296 million referred to Global Gas & LNG Portfolio segment for €5,711 million and was affected by the decline in energy commodity prices which decreased the nominal value of the payables. This decrease was partially offset by the increase in the Enilive, Refining and Chemicals segment for €493 million.

Other payables included: (i) payables to factoring companies in relation to the derecognition of Eni's tax credits for €728 million (€246 million at December 31, 2022); (ii) payroll payables for €287 million (€255 million at December 31, 2022); (iii) the amounts still due to the triggering of the take-or-pay clause of the long-term supply contracts for €187 million (€284 million at December 31, 2022); (iv) payables for social security contributions for €110 million (€100 million at December 31, 2022).

Trade and other payables were denominated in euro for €10,200 million and in U.S. dollar for €10,421 million.

Because of the short-term maturity and conditions of remuneration of trade payables, the fair values approximated the carrying amounts.

Trade and other payables due to related parties are described in note 36 – Transactions with related parties.

19 Finance debt

	December 31, 2023				December 31, 2022
	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
(€ million)
Banks	2,810	600	1,116	4,526	3,645	851	1,999	6,495
Ordinary bonds		1,956	19,535	21,491		2,142	17,368	19,510
Sustainability-linked
convertible bonds		9	917	926
Other financial
institutions	1,282	356	148	1,786	801	104	7	912
	4,092	2,921	21,716	28,729	4,446	3,097	19,374	26,917

Finance debt increased by €1,812 million as disclosed in table "Changes in liabilities arising from financing activities" detailed at the end of this paragraph.

As of December 31, 2023, finance debt included €701 million of sustainability-linked financial contracts with leading banking institutions which provide for an adjustment mechanism of the funding cost linked to the achievement of certain sustainability targets, which are disclosed in the comment of ordinary bonds.

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. At December 31, 2023, debts subjected to restrictive covenants amounted to €732 million (€862 million at December 31, 2022). 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 €16.8 billion were drawn as of December 31, 2023.

The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2023:

accrued (€ million) Amount expense Total Currency Maturity Rate % Issuing entity Euro Medium Term Notes Eni SpA 1,250 22 1,272 EUR 2033 4.250 Eni SpA 1,200 14 1,214 EUR 2025 3.750 Eni SpA 1,000 31 1,031 EUR 2029 3.625 Eni SpA 1,000 12 1,012 EUR 2026 1.500 Eni SpA 1,000 4 1,004 EUR 2030 0.625 Eni SpA 1,000 4 1,004 EUR 2026 1.250 Eni SpA 1,000 10 1,010 EUR 2031 2.000 Eni SpA 900 1 901 EUR 2024 0.625 Eni SpA 800 3 803 EUR 2028 1.625 Eni SpA 750 13 763 EUR 2024 1.750 Eni SpA 750 8 758 EUR 2027 1.500 Eni SpA 750 (3) 747 EUR 2034 1.000 Eni SpA 679 10 689 USD 2027 variable Eni SpA 650 5 655 EUR 2025 1.000 Eni SpA 600 (2) 598 EUR 2028 1.125 Eni SpA 500 3 503 EUR 2025 1.275 Eni SpA 452 452 USD 2026 variable Eni SpA 452 (1) 451 USD 2026 variable Eni SpA 100 4 104 EUR 2028 5.441 Eni SpA 75 2 77 EUR 2043 3.875 Eni SpA 70 1 71 EUR 2032 4.000 Eni SpA 50 (1) 49 EUR 2031 4.800 Eni SpA – Sustainability linked 1,000 (1) 999 EUR 2028 0.375 Eni SpA – Sustainability linked 750 14 764 EUR 2027 3.625 16,778 153 16,931 Other bonds Eni SpA 905 7 912 USD 2028 4.750 Eni SpA 905 1 906 USD 2029 4.250 Eni USA Inc 362 1 363 USD 2027 7.300 Eni SpA 317 1 318 USD 2040 5.700 Eni Plenitude Wind 2022 SpA 17 17 EUR 2031 variable Eni SpA – Sustainability linked - Retail 2,000 44 2,044 EUR 2028 4.300 4,506 54 4,560 21,284 207 21,491		Discount on bond issue and

During 2023, a total of €4,000 million of ordinary bond were issued. The new issues concerned, in particular, a bond of €1,250 million within the Euro Medium Term Notes program and two sustainability-linked bond, the first intended for a retail public of €2,000 million and the second as part of the Euro Medium Term Notes program of €750 million. The sustainability parameters are: (i) net carbon footprint upstream (GHG emission Scope 1 and 2) equal to or less than 5.2 million tons of CO2 equivalent by December 31, 2025; (ii) renewable energy installed capacity of at least or more than 5 GW December 31, 2025. In case the Company misses those targets, a step-up mechanism will be applied, increasing the interest cost.

In addition, within the Euro Medium Term Notes program, a sustainability-linked bond was outstanding for a total nominal amount of €1,000 million which was indexed to achievement of the following sustainability targets: (i) net carbon footprint upstream (GHG emission Scope 1 and 2) equal to or less than 7.4 million tons of CO2 equivalent by 2024; (ii) renewable energy installed capacity of at least or more than 5 GW by 2025. In case the Company misses those targets, a stepup mechanism will be applied, increasing the interest cost.

As of December 31, 2023, ordinary bonds maturing within 18 months amounted to €2,821 million.

Information relating to the senior unsecured sustainability-linked convertible bonds is as follows:

(€ million) Issuing entity	Amount	Discount on bond issue and accrued expense	Total	Currency	Maturity	Rate %
Eni SpA – Convertible senior unsecured sustainability linked bonds	1,000	5	1,005	EUR	2030	2.950
of which financial liabilities	920	6	926	EUR
of which equity	80	(1)	79	EUR

During 2023, Eni SpA issued 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 programme approved by the Shareholders' Meeting held on 10 May 2023. The bonds will have a maturity of 7 years, will be issued at 100% of par and will pay an annual coupon of 2.95%. The conversion price will be €17.5513, representing a premium of 20% above the reference price of €14.6261, which has been determined as the volume weighted average price of Eni ordinary shares on the regulated market of Borsa Italiana on September 7, 2023, between the opening of trading and the pricing of the offering. The bonds will be linked to the achievement of sustainability targets related to Net Carbon Footprint Upstream (Scope 1 and 2) and renewable energy installed capacity, as detailed in the relevant terms and conditions.

The following table provides a breakdown by currency of finance debt and the related weighted average interest rates:

	December 31, 2023			December 31, 2022
	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	3,469	3.3	20,293	2.4	3,994	0.9	17,171	1.8
U.S. dollar	614	5.5	4,342	5.9	337	2.2	5,298	5.1
Other currencies	9	2.5	2	5.9	115		2	2.4
	4,092		24,637		4,446		22,471

As of December 31, 2023, Eni retained committed borrowing facilities of €9,120 million (€8,298 million at December 31, 2022). Those facilities bore interest rates reflecting prevailing conditions in the marketplace. The breakdown of committed borrowing facilities are as follows:

(€ million)	December 31, 2023	December 31, 2022
Undrawn long-term sustainability-linked credit facilities with current portion of long-term	9,000	8,100
Other undrawn long-term borrowing facilities	12	2
Other drawn long-term borrowing facilities with current portion of long-term	3	70
Long-term borrowing facilities	9,015	8,172
Undrawn short-term borrowing facilities	38	43
Drawn short-term borrowing facilities	67	83
Short-term borrowing facilities	105	126
	9,120	8,298

As of December 31, 2023, 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:

	December	December
(€ million)	31, 2023	31, 2022
Ordinary bonds and sustainability-linked bonds	21,025	18,167
Convertible sustainability-linked bonds	1,061
Banks	1,652	2,733
Other financial institutions	505	111
	24,243	21,011

Fair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from 1.9% to 5.2% (1.8% and 5.1% at December 31, 2022).

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 liabilietis	Total
2023
Carrying amount - beginning of the year	22,471	4,446	4,951	31,868
Cash flows	1,810	(1,495)	(963)	(648)
Currency translation differences	(144)	182	(116)	(78)
Changes in the scope of consolidation	38	352	13	403
Other non-monetary changes	462	607	1,451	2,520
Carrying amount - end of the year	24,637	4,092	5,336	34,065
2022
Carrying amount - beginning of the year	25,495	2,299	5,337	33,131
Cash flows	(3,944)	1,375	(994)	(3,563)
Currency translation differences	208	547	289	1,044
Changes in the scope of consolidation	477	(95)	(1,953)	(1,571)
Other non-monetary changes	235	320	2,272	2,827
Carrying amount - end of the year	22,471	4,446	4,951	31,868

Changes in the scope of consolidation referred to the acquisition of Novamont for €211 million and to the acquisitions in relation to renewables activities of the Plenitude business line for €33 million.

Other non-monetary changes include lease liabilities assumptions for €1,584 million and €1,047 million of trade payables on which payment term extensions have been negotiated, resulting in the classification of the debt as financial. 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

20 Information on net borrowings

	December	December
(€ million)	31, 2023	31, 2022
A. Cash	3,731	3,351
B. Cash equivalents	6,462	6,804
C. Other current financial assets	7,637	9,736
D Liquidity (A+B+C)	17,830	19,891
E. Current financial debt	6,057	6,588
F. Current portion of non-current financial debt	2,084	1,839
G. Current financial indebtedness (E+F)	8,141	8,427
H. Net current financial indebtedness (G-D)	(9,689)	(11,464)
I. Non-current financial debt	5,472	6,073
J. Debt instruments	20,452	17,368
K. Non‐current trade and other payables
L. Non-current financial indebtedness (I+J+K)	25,924	23,441
M. Total financial indebtedness (H+L)	16,235	11,977

Cash and cash equivalents include €205 million (€97 million at December 31, 2022) subject to foreclosure measures and payment guarantees.

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.

Current portion of non-current financial debt and non-current financial debt include lease liabilities of €1,128 million and €4,208 million (€884 million and €4,067 million at December 31, 2022, respectively), of which €480 million (€494 million at December 31, 2022) related to the share of joint operators in upstream projects operated by Eni which will be recovered through a partner cash-call billing process. More information on lease liabilities is reported in note 13 – Right-of-use assets and lease liabilities.

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 OIL insurance coverage	Other	Total
Carrying amount at December 31,
2022	9,322	3,503	947	219	327	189	97	663	15,267
New or increased provisions	310	783	132	16	97	20	3	574	1,935
Initial recognition and changes in estimates	748								748
Accretion
discount	284	57							341
Reversal of utilized
provisions Reversal of unutilized	(731)	(476)	(202)	(16)	(161)			(75)	(1,661)
provisions	(5)	(224)	(219)	(8)		(15)	(4)	(41)	(516)
Currency translation differences	(156)	(2)	(11)	(4)		(1)		(4)	(178)
Change in scope of consolidation	88								88
Other changes Carrying amount at December 31,	(390)	(28)	34	(24)	(18)	15	9	(89)	(491)
2023	9,470	3,613	681	183	245	208	105	1,028	15,533

The decommissioning provision comprised: (i) for €8,027 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 €817 million the estimated costs for social projects in the Exploration & Production segment, relating for €442 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 €547 million the estimated dismantling and restoration costs of production lines and auxiliary logistics structures of the Enilive and Refining business. In 2023, the main changes in the decommissioning provision related to: (i) revision of cost estimates relating to oil & gas assets completely written-down or no more producing for €185 million; (ii) a €92 million cost estimate for dismantling and removing production lines and auxiliary refining logistics structures for which management assessed the absence of economic prospects in the current scenario of refined products, as well as lack of any economic options of reconversion or reuse in a decarbonisation processes; (iii) for €33 million the decommissioning of a petrochemical plant and the consequent restoration of the site.

Initial recognition and changes in estimates were primarily recognized at assets in UK, Italy, USA and Libya. The provision also increased due to a reduction in discounting rates in relation to the downward movement of the Euro yield curve. The unwinding of discount recognized through profit and loss was determined based on discount rates ranging from 2.2% to 5.4% (from -0.3% to 6.1% at December 31, 2022). Changes in the scope of consolidation mainly referred to Exploration & Production segment for €87 million. Main expenditures associated with decommissioning operations are expected to be incurred over a fifty-year period, with utilizations essentially starting after 12 months.

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 presently are no more in compliance with current environmental laws and regulations, or because Eni assumed the liability borne by other operators when the Company acquired or otherwise took over 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 €283 million to remediation activities at brownfield sites in Italy and costs related to groundwater treatments; (ii) for about €200 million to refining plants, depots, fuel distribution systems and oil pipelines; (iii) for €58 million to remediation activities at petrochemical plants. At December 31, 2023, environmental provision primarily related to Eni Rewind SpA for €2,391 million and to the Enilive and Refining business line for €739 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 €290 million.

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 €154 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 DAC represented the estimated liabilities accrued on the basis for third party claims. Against such liability were recorded receivables for €38 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 €168 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.

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 €1.3 billion.

22 Provisions for employee benefits

	December	December
(€ million)	31, 2023	31, 2022
Italian defined benefit plans	156	177
Foreign defined benefit plans	121	142
FISDE, foreign medical plans and other	118	126
Defined benefit plans	395	445
Other benefit plans	353	341
Provision for employee benefits	748	786

The liability relating to Eni's commitment to cover the healthcare costs of personnel is determined based on the contributions paid by the Company.

Other employee benefit plans related to deferred monetary incentive plans for €120 million, expansion contracts for €118 million, isopensione plans (a post retirement benefit plan applicable to a specific category of employees) of Eni Plenitude SpA Società Benefit for €77 million, Jubilee Awards for €26 million and other long-term plans for €12 million.

Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

	2023					2022
	Italian defined benefit	Foreign defined benefit	FISDE,foreign medical plans	Defined benefit	Other benefit		Italian defined benefit	Foreign defined benefit	FISDE, foreign medical plans and	Defined benefit	Other benefit
(€ million) Present value of benefit	plans	plans	and other	plans	plans	Total	plans	plans	other	plans	plans	Total
liabilities at beginning of year	177	644	126	947	341	1,288	227	761	162	1,150	301	1,451
Current service cost	1	10	2	13	51	64	1	11	3	15	52	67
Interest cost	6	29	4	39	10	49	2	24	2	28	1	29
Remeasurements:	5	24	1		(2)		(26)	(118)	(33)		(22)
- actuarial (gains) losses due to changes in				30		28				(177)		(199)
demographic assumptions - actuarial (gains) losses	1	1		2	(1)	1		9		9	(2)	7
due to changes in financial assumptions	4	8	2	14	1	15	(34)	(144)	(35)	(213)	(15)	(228)
- experience (gains) losses		15	(1)	14	(2)	12	8	17	2	27	(5)	22
Past service cost and
(gain) loss on settlements	2	(13)	4	(7)	91	84					127	127
Plan contributions:		1		1		1		1		1		1
- employee contributions		1		1		1		1		1		1
Benefits paid Reclassification to liabilities directly associated with assets held	(37)	(39)	(9)	(85)	(97)	(182)	(28)	(30)	(8)	(66)	(87)	(153)
for sale		(147)	(6)	(153)	(2)	(155)		(2)	(2)	(4)		(4)
Currency translation differences and other
changes Present value of benefit liabilities at end of year	2	(129)	(4)	(131)	(39)	(170)	1	(3)	2		(31)	(31)
(a)	156	380	118	654	353	1,007	177	644	126	947	341	1,288
Plan assets at beginning of year		503		503		503		633		633		633
Interest income		19		19		19		18		18		18
Return on plan assets								(117)		(117)		(117)
Past service cost and
(gains) losses settlements								(1)		(1)		(1)
Plan contributions:		25		25		25		14		14		14
- employee contributions		1		1		1		1		1		1
- employer contributions		24		24		24		13		13		13
Benefits paid		(31)		(31)		(31)		(21)		(21)		(21)
Reclassification to liabilities directly associated with assets held
for sale		(123)		(123)		(123)
Currency translation differences and other
changes		(132)		(132)		(132)		(23)		(23)		(23)
Plan assets at end of year (b)		261		261		261		503		503		503
Asset ceiling at
beginning of year Change in asset ceiling		1 1		1		1		1		1		1
Asset ceiling at end of				1		1
year (c)		2		2		2		1		1		1
Net liability recognized at end of year (a-b+c)	156	121	118	395	353	748	177	142	126	445	341	786

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
2023
Current service cost	1	10	2	13	51	64
Past service cost and (gains) losses on
settlements	2	(13)	4	(7)	91	84
Interest cost (income), net:
- interest cost on liabilities	6	29	4	39	10	49
- interest income on plan assets		(19)		(19)		(19)
Total interest cost (income), net	6	10	4	20	10	30
- of which recognized in "Payroll and related cost"					10	10
- of which recognized in "Financial income
(expense)"	6	10	4	20		20
Remeasurements for long-term plans					(2)	(2)
Administrative fees paid
Total	9	7	10	26	150	176
- of which recognized in "Payroll and related
cost"	3	(3)	6	6	150	156
- of which recognized in "Financial income
(expense)"	6	10	4	20		20
2022
Current service cost	1	11	3	15	52	67
Past service cost and (gains) losses on
settlements					127	127
Interest cost (income), net:
- interest cost on liabilities	2	24	2	28	1	29
- interest income on plan assets		(18)		(18)		(18)
Total interest cost (income), net	2	6	2	10	1	11
- of which recognized in "Payroll and related cost"					1	1
- of which recognized in "Financial income
(expense)"	2	6	2	10		10
Remeasurements for long-term plans					(22)	(22)
Administrative fees paid		1		1		1
Total	3	18	5	26	158	184
- of which recognized in "Payroll and related
cost"	1	12	3	16	158	174
- of which recognized in "Financial income (expense)"	2	6	2	10		10
	F-80

Costs of defined benefit plans recognized in other comprehensive income consisted of the following:

		2023				2022
(€ 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 (gains)/losses due to
changes in demographic
assumptions	1	1		2		9		9
Actuarial (gains)/losses due to
changes in financial assumptions	4	8	2	14	(34)	(144)	(35)	(213)
Experience (gains) losses		15	(1)	14	8	17	2	27
Return on plan assets						117		117
Changes in asset ceiling		1		1
Remeasurements	5	25	1	31	(26)	(1)	(33)	(60)

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, 2023
Plan assets with a quoted market price	4	24	121	11	55		5	15	235
Plan assets without a quoted market
price							26		26
	4	24	121	11	55		31	15	261
December 31, 2022
Plan assets with a quoted market price	23	25	260	11	4	4	26	146	499
Plan assets without a quoted market
price							4		4
	23	25	260	11	4	4	30	146	503
				F-81

The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2024 consisted of the following:

		Italian defined benefit plans	Foreign defined benefit plans	FISDE	Other benefit plans
2023
Discount rate	(%)	3.1	1.4-25.9	3.1	3.1-3.3
Rate of compensation increase	(%)	3.0	1.9-20.0
Rate of price inflation	(%)	2.0	1.2-15.5	2.0	2.0
Life expectations on retirement at age 65	(years)		14-23	24
2022
Discount rate	(%)	3.7	2.2-15.4	3.7	3.4-3.7
Rate of compensation increase	(%)	3.4	1.9-12.5
Rate of price inflation	(%)	2.4	1.2-11.5	2.4	2.4
Life expectations on retirement at age 65	(years)		13-24	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
2023
Discount rate	(%)	3.2-3.3	1.4-4.5	3.2-25.9	6.9	1.4-25.9
Rate of compensation increase	(%)	1.9-3.0	3.0	5.0-20.0	5.0	1.9-20.0
Rate of price inflation	(%)	1.9-2.1	1.2-3.4	3.1-15.5	3.5	1.2-15.5
Life expectations on retirement
at age 65	(years)	21-23	23	14-18		14-23
2022
Discount rate	(%)	3.5-3.8	2.2-4.8	3.8-15.4	7.0	2.2-15.4
Rate of compensation increase	(%)	1.9-3.0	3.0-4.0	1.9-12.5	5.0	1.9-12.5
Rate of price inflation	(%)	1.9-2.2	1.2-3.5	3.0-11.5	3.0	1.2-11.5
Life expectations on retirement
at age 65	(years)	21-22	23-24	13-17		13-24

The effects of a possible change in the main actuarial assumptions at the end of the year are not material.

The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €147 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:

	Italian defined benefit	Foreign defined benefit	FISDE, foreign medical plans and	Other benefit
(€ million)	plans	plans	other	plans
December 31, 2023
2024	14	24	9	107
2025	13	22	9	103
2026	14	23	7	86
2027	16	22	7	30
2028	18	23	7	14
2029 and thereafter	81	7	79	13
Weighted average duration (years)	6.8	13.6	10.8	2.3
December 31, 2022
2023	14	29	7	94
2024	13	28	7	95
2025	14	26	7	85
2026	17	35	7	30
2027	15	31	7	16
2028 and thereafter	104	(7)	91	21
Weighted average duration (years)	7.5	13.2	11.5	2.5

23 Deferred tax assets and liabilities

	December	December
(€ million)	31, 2023	31, 2022
Deferred tax liabilities before offsetting	8,461	9,315
Deferred tax assets available for offset	(3,759)	(4,221)
Deferred tax liabilities	4,702	5,094
Deferred tax assets before offsetting (net of accumulated write-down provisions)	8,241	8,790
Deferred tax liabilities available for offset	(3,759)	(4,221)
Deferred tax assets	4,482	4,569

The most significant temporary differences giving rise to net deferred tax assets and liabilities are disclosed below:

	Carrying amount at	Carrying amount at
(€ million)	December 31, 2023	December 31, 2022
Deferred tax liabilities
Accelerated tax depreciation	6,028	6,707
Derivative financial instruments	451	788
Difference between the fair value and the carrying amount of assets acquired	305	288
Site restoration and abandonment (tangible assets)	265	276
Leasing	150	162
Application of the weighted average cost method in evaluation of inventories	47	52
Other	1,215	1,042
	8,461	9,315
Deferred tax assets, gross
Carry-forward tax losses	(5,677)	(6,752)
Site restoration and abandonment (provisions for contingencies)	(1,802)	(1,986)
Timing differences on depreciation and amortization	(1,567)	(1,710)
Impairment losses	(1,517)	(1,490)
Accruals for impairment losses and provisions for contingencies	(1,279)	(1,246)
Leasing	(198)	(182)
Employee benefits	(168)	(161)
Unrealized intercompany profits	(57)	(68)
Derivative financial instruments	(236)	(60)
Over/Under lifting	(124)	(59)
Other	(1,284)	(1,246)
	(13,909)	(14,960)
Accumulated write-downs of deferred tax assets	5,668	6,170
Deferred tax assets, net	(8,241)	(8,790)

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
2023
Carrying amount - beginning of the year	9,315	(14,960)	6,170	(8,790)
Additions	654	(2,161)	639	(1,522)
Deductions	(1,099)	2,565	(861)	1,704
Changes with effect to OCI	(69)	223		223
Currency translation differences	(247)	213	(68)	145
Change in scope of consolidation	348	(183)	13	(170)
Other changes	(441)	394	(225)	169
Carrying amount - end of the year	8,461	(13,909)	5,668	(8,241)
2022
Carrying amount - beginning of the year	10,668	(17,150)	8,604	(8,546)
Additions	1,176	(2,215)	464	(1,751)
Deductions	(1,351)	2,532	(2,409)	123
Changes with effect to OCI	382	(147)		(147)
Currency translation differences	611	(610)	165	(445)
Change in scope of consolidation	(1,951)	2,279	(549)	1,730
Other changes	(220)	351	(105)	246
Carrying amount - end of the year	9,315	(14,960)	6,170	(8,790)

Carry-forward tax losses amounted to €21,896 million, of which €17,319 million can be carried forward indefinitely. Carryforward tax losses were €12,063 million at Italian subsidiaries and €9,833 million at foreign subsidiaries. Deferred tax assets gross of accumulated write-downs recognized on these losses amounted to €2,895 million and €2,782 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 28.3%.

Accumulated write-downs of deferred tax assets related to Italian companies for €3,975 million and non-Italian companies for €1,693 million.

Deferred tax assets of Italian companies of €538 million were restored in relation to an expected higher taxable income.

Taxes are also described in note 33 – Income taxes.

24 Derivative financial instruments and hedge accounting

	December 31, 2023			December 31, 2022
(€ 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 exchange rate
- Currency swap	70	168	2	110	132	2
- Interest currency swap		84	2	1	144	2
- Outright				3	12	2
	70	252		114	288
Derivatives on interest rate
- Interest rate swap	62	34	2	137	58	2
	62	34		137	58
Derivatives on commodities
- Over the counter	2,902	2,103	2	9,571	8,663	2
- Future	3,027	2,905	1	6,886	5,764	1
- Options	106	114	2		2	1
- Other	11		2		80	2
	6,046	5,122		16,457	14,509
	6,178	5,408		16,708	14,855
Cash flow hedge derivatives
Derivatives on commodities
- Over the counter	80	13	2
- Future				339	192	1
	80	13		339	192
Derivatives on interest rate
- Interest rate swap	6		1	21		2
	6			21
	86	13		360	192
Options
- Other options		41	2		144	3
		41			144
Gross amount	6,264	5,462		17,068	15,191
Offsetting	(2,895)	(2,895)		(5,863)	(5,863)
Net amount	3,369	2,567		11,205	9,328
Of which:
- current	3,323	2,414		11,076	9,042
- non-current	46	153		129	286

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 expected cash flows 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 this risk in relation to the underlying commodities, 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 values of non-hedging derivatives essentially 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.

Fair value of cash flow hedge derivatives essentially related to commodity hedges were entered into by the Global Gas & LNG Portfolio segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future trade transactions of gas or electricity 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.

Eni entered into sustainability-linked interest rate swaps with leading banking institutions which provide for a cost adjustment mechanism linked to the achievement of certain sustainability targets. At December 31, 2023, the fair value of these contracts amounted to positive €15 million.

In 2023, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €2,562 million was hedged by using, in a fair value hedge relationship, positive exchange differences for €75 million resulting on a portion of bonds denominated in U.S. dollars amounting to €2,135 million.

The offsetting of financial derivatives primarily related to Eni Global Energy Markets SpA.

During 2023, there were no transfers between the different hierarchy levels of fair value.

Hedging derivative instruments are disclosed below:

	December 31, 2023			December 31, 2022
(€ 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	310	147	6	83	(4)
- Future		(23)		1,350	(3,912)	275
- Other					9
	310	124	6	1,433	(3,907)	275
Derivatives on interest rate
- Interest rate swap	128	(19)		127	24
	128	(19)		127	24
	438	105	6	1,560	(3,883)	275
F-87

The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge is provided below:

	December 31, 2023			December 31, 2022
(€ million)	Change of the underlying asset used for the calculation of hedging ineffectiveness	CFH reserve	Reclassification adjustments	Change of the underlying asset used for the calculation of hedging ineffectiveness	CFH reserve	Reclassification adjustments
Cash flow hedge derivatives
Commodity price risk
- Planned sales	(169)	56	(436)	4,059	(499)	(4,666)
	(169)	56	(436)	4,059	(499)	(4,666)
Derivatives on interest rate
- hedged flows	(19)	(6)		(15)	16	(11)
	(19)	(6)		(15)	16	(11)
	(169)	50	(436)	4,044	(483)	(4,677)

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)	2023	2022	2021
Net income (loss) on cash flow hedging derivatives	6	275	(51)
Net income (loss) on other derivatives	472	(2,011)	954
	478	(1,736)	903

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)	2023	2022	2021
Derivatives on exchange rate	(63)	(70)	(322)
Derivatives on interest rate	2	81	16
Options		2
	(61)	13	(306)

Net financial 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 formulas of commodities.

More information is disclosed in note 36 – Transactions with related parties.

25 Assets held for sale and liabilities directly associated with assets held for sale

As of December 31, 2023, assets held for sale of €2,609 million (€264 million at 31 December 2022) and directly associated liabilities of €1,862 million (€108 million at 31 December 2022) mainly concerned the agreement for the sale of onshore assets in Nigeria and some licenses and exploration permits in Congo. The carrying amount of assets held for sale and liabilities directly associated amounted to €2,597 million (of which current assets €846 million) and €1,862 million (of which current liabilities €681 million), respectively.

During 2023, assets reclassified to held for sale in the 2022 financial statements relating to natural gas transportation activities from Algeria and exploration activities in Gabon were sold (see note 5 – Business combinations and other significant transactions).

26 Equity

Non-controlling interest

	Net Profit		Equity
(€ million)	2023	2022	December 31, 2023	December 31, 2022
EniPower Group	86	54	406	373
Eni Plenitude Group	3	20	54	97
Others				1
	89	74	460	471

Equity attributable to equity holders of Eni

	December 31,	December 31,
(€ million)	2023	2022
Share capital	4,005	4,005
Retained earnings	32,988	23,455
Cumulative currency translation differences	5,238	7,564
Other reserves and equity instruments:
- Perpetual subordinated bonds	5,000	5,000
- Legal reserve	959	959
- Reserve for treasury shares	2,333	2,937
- Reserve for OCI on cash flow hedging derivatives net of tax effect	36	(342)
- Reserve for OCI on defined benefit plans net of tax effect	(88)	(58)
- Reserve for OCI on equity-accounted investments	98	46
- Reserve for OCI on other investments valued at fair value	98	53
- Reserve for convertible bond issue	79
- Other reserves		190
Treasury shares	(2,333)	(2,937)
Profit for the year	4,771	13,887
	53,184	54,759

<-- PDF CHUNK SEPARATOR -->

Share capital

As of December 31, 2023, the parent company's issued share capital consisted of €4,005,358,876 (same amount as of December 31, 2022) represented by 3,375,937,893 ordinary shares without nominal value (3,571,487,977 ordinary shares at December 31, 2022).

On May 10, 2023, 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 2023 of €0.94 per share in four tranches, in September 2023 (for an amount equal to €0.24 per share), November 2023 (for an amount equal to €0.23 per share), March 2024 (for an amount equal to €0.24) and May 2024 (for an amount equal to €0.23); (ii) to cancel 195,550,084 treasury shares with no par value without changing the amount of the share capital and reducing the related reserve by the amount of €2,400 million (equal to the carrying value of the cancelled shares); (iii) 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 for a total outlay of up to €3.5 billion of Company's ordinary shares in a maximum number equal to 337,000,000 by April 30, 2024, of which: (a) up to a maximum of 275,000,000 shares for the purchase of treasury shares for the purpose of remunerating Shareholders; (b) up to a maximum of 62,000,000 shares for setting up the so-called share stock. In execution of this resolution, as of December 31, 2023, 128,894,264 treasury shares had been purchased for a total value of €1,837 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 English law and are traded on the regulated market of the Luxembourg Stock Exchange. As of December 31, 2023, hybrid bonds amounted to €5 billion (same amount as at December 31, 2022).

The key characteristics of the two bonds are: (i) an issue of €1.5 billion perpetual 5.25-year subordinated non-call hybrid notes with a re-offer price of 99.403% and an annual fixed coupon of 2.625% until the first reset date of January 13, 2026. 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 316.7 basis points, increased by an additional 25 basis points as from January 13, 2031 and a subsequent increase of additional 75 basis points as from January 13, 2046; (ii) an issue of €1.5 billion perpetual 9-year subordinated noncall 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; (iii) an issue of €1 billion perpetual 6-year subordinated non-call hybrid notes with a re-offer price of 100% and an annual fixed coupon of 2.000% until the first reset date of May 11, 2027. 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 220.4 basis points, increased by additional 25 basis points as from May 11, 2032 and a subsequent increase of additional 75 basis points as from May 11, 2047; (iv) an issue of €1 billion perpetual 9-year subordinated non-call hybrid notes with a re-offer price of 99.607% and an annual fixed coupon of 2.750% until the first reset date of May 11, 2030. 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 277.1 basis points, increased by additional 25 basis points as from May 11, 2035 and a subsequent increase of additional 75 basis points as from May 11, 2050.

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.

Reserves for Other Comprehensive Income

	Reserve for OCI on cash flow hedge derivatives		Reserve for OCI on defined benefit plans			Reserve for OCI on	Reserve for
(€ million)	Gross reserve	Deferred tax liabilities	Net reserve	Gross reserve	Deferred tax liabilities	Net reserve	equity accounted investments (*)	OCI on investments valued at fair value
Reserve as of December 31,
2022	(483)	141	(342)	(20)	(38)	(58)	46	53
Changes of the year	105	(32)	73	(31)	10	(21)	52	45
Currency translation differences				(43)	34	(9)
Reversal to inventories
adjustments	(8)	3	(5)
Reclassification to retained earnings
Changes in scope of consolidation
Reclassification adjustments	436	(126)	310
Reserve as of December 31,
2023	50	(14)	36	(94)	6	(88)	98	98
Reserve as of December 31,
2021	(1,269)	373	(896)	(84)	(33)	(117)	54	141
Changes of the year	(3,883)	1,133	(2,750)	60	(5)	55	92	56
Currency translation differences				1		1
Reversal to inventories
adjustments	(8)	2	(6)
Reclassification to retained
earnings								(144)
Changes in scope of
consolidation				3		3	1
Reclassification adjustments	4,677	(1,367)	3,310				(101)
Reserve as of December 31,
2022	(483)	141	(342)	(20)	(38)	(58)	46	53

(*) Reserve for OCI on equity-accounted investments at December 31, 2023 includes negative reserves of €1 million relating to defined benefit plans (€1 million at December 31, 2022)

Treasury shares

A total of 157,115,336 of Eni's ordinary shares (226,097,834 at December 31, 2022) were held in treasury for a total cost of €2,333 million (€2,937 million at December 31, 2022).

During 2023, 128,894,264 shares were acquired, for a total value of €1,837 million, 195,550,084 treasury shares have been cancelled for a total value of €2,400 million and 2,326,678 treasury shares were assigned free of charge to Eni executives, 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.

Distributable reserves

As of December 31, 2023, equity attributable to Eni included distributable reserves of approximately €43 billion.

Reconciliation of profit and equity of the parent company Eni SpA to the consolidated profit and equity

	Profit		Shareholders' equity
(€ million)	2023	2022	December 31, 2023	December 31, 2022
As recorded in Eni SpA's Financial Statements	3,272	5,403	51,019	52,520
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company	3,202	7,375	(814)	(1,302)
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity			153	153
- adjustments to comply with Group accounting policies	(2,266)	797	3,774	4,468
- elimination of unrealized intercompany profits	86	124	(437)	(533)
- deferred taxation	566	262	(51)	(76)
	4,860	13,961	53,644	55,230
Non-controlling interest	(89)	(74)	(460)	(471)
As recorded in Consolidated Financial Statements	4,771	13,887	53,184	54,759

27 Other information

Supplemental cash flow information

(€ million)	2023	2022	2021
Investment in consolidated subsidiaries and businesses
Current assets	408	147	262
Non-current assets	1,985	1,981	1,124
Net borrowings	(91)	(541)	(486)
Current and non-current liabilities	(622)	(366)	(349)
Net effect of investments	1,680	1,221	551
Goodwill	25	482	1,574
Fair value of investments held before the acquisition of control	(271)	(21)	(99)
Non-controlling interests	(2)	(15)	(4)
Purchase price	1,432	1,667	2,022
less:
Cash and cash equivalents acquired	(155)	(31)	(121)
Consolidated subsidiaries and businesses net of cash and cash equivalent
acquired	1,277	1,636	1,901
Disposal of consolidated subsidiaries and businesses
Current assets	130	1,377	2
Non-current assets	153	8,618
Net borrowings	180	(2,085)
Current and non-current liabilities	(124)	(2,351)
Net effect of disposals	339	5,559	2
Current value of the stake held for business combinations	(580)	(5,726)
Reclassification among other items of OCI	(7)	(918)
Gain on disposal of business combinations	427	2,704
Fair value of share capital held after the sale of control	414
Credits for divestments	(173)	(1,609)
Selling price	420	10	2
less:
Cash and cash equivalents sold	(25)	(70)
Consolidated subsidiaries and businesses net of cash and cash equivalent
disposed of before business combination	395	(60)	2
Business combination Unión Fenosa Gas
Investment in Unión Fenosa Gas sold			232
less:
Investments and businesses acquired
Current assets			370
Non-current assets			378
Net borrowings			(128)
Long-term and short-term liabilities			(420)
Total investments and businesses acquired			200
Total net disposals			32
less:
Cash and cash equivalents acquired			42
Business combination Unión Fenosa Gas net of cash and cash equivalent
acquired			74
Consolidated subsidiaries and businesses net of cash and cash equivalent
disposed of	395	(60)	76

Investments and disposals in 2023 are disclosed in note 5 – Business combinations and other significant transactions.

Investments in 2022 concerned: (i) the 100% acquisition of the company SKGR Energy Single Member SA (now Eni Plenitude Renewables Hellas Single Member SA), which owns a pipeline of photovoltaic projects totalling around 800 MW in Greece; (ii) the acquisition of the Corazon I Solar plant with 266 MW of capacity, in Texas (USA) and the Guajillo storage project; (iii) the acquisition of 100% of the company Energía Eólica Boreas SLU, with a generation capacity of 104.5 MW; (iv) the acquisition of a 100% stake in the company Export LNG Ltd which owns the Tango FLNG floating liquefaction plant; (v) the acquisitions of PLT Energia Srl (now Eni Plenitude Wind & Energy Srl) and SEF Srl (now Eni Plenitude Solar & Miniwind Italia Srl).

Disposals in 2022 concerned: (i) the establishment by bp and Eni of Azule Energy Holdings Ltd, a 50/50 joint venture combining the two partners' Angolan hydrocarbon exploration and production assets. The transaction resulted in the loss of control of Eni Angola SpA, Eni Angola Exploration BV and Eni Angola Production BV which were contributed to Azule Energy Holdings Ltd in exchange of a 50% stake in the new entity; (ii) the disposal of 100% of the consolidated company Eni North Sea Wind Ltd which owned a 20% interest in the Dogger Bank A, B and C projects in the United Kingdom to the Norwegian joint venture Vårgrønn AS (Eni's interest 65%); (iii) the disposal of the stakes in exploration and production activities in Pakistan.

Investments in 2021 concerned: (i) the acquisition of a 100% stake of Aldro Energía y Soluciones SLU (now Eni Plenitude Iberia SLU) active in the market for the sale of power, gas and services in the retail business; (ii) the acquisition of a 100% stake of the company FRI-EL Biogas Holding (now EniBioCh4in SpA) active in the sector of power production from bioenergy; (iii) the acquisition from Glennmont Partners and PGGM Infrastructure Fund of a portfolio of thirteen operating onshore wind farms, with a total capacity of 315 MW; (iv) the acquisition of Dhamma Energy Group; (v) the acquisition from Azora Capital of a portfolio of nine renewable energy projects consisting of three wind farms in operation and one under construction for a total of 234 MW and five photovoltaic projects in an advanced stage of development for approximately 0.9 GW; (vi) the acquisition of control of Finproject by exercising the call option on the remaining 60% of the share capital, after the initial investment of 40% made in 2020; (vii) a 100% stake in Be Power, acquired by Zouk Capital and Aretex, companies active in the segment of charging infrastructure for power mobility.

Disposals in 2021 concerned the restructuring of the joint venture Unión Fenosa Gas SA following the agreements with the authorities of the Arab Republic of Egypt (ARE) and the Spanish partner Naturgy for the resolution of all outstanding issues of the joint venture with Egyptian partners which resulted in an overall cash adjustment for the benefit of Eni, represented in the disposals.

Business combinations

The provisional and definitive price allocation of the net assets acquired in 2022 is shown below:

(€ million)	Energía Eólica Boreas SLU (Provisional allocation)	Energía Eólica Boreas SLU (Definitive allocation)	PLT (PLT Energia Srl e SEF Srl) (Provisional allocation)	PLT (PLT Energia Srl e SEF Srl) (Definitive allocation)
Current assets	1	1	145	145
Property, plant and equipment	100	100	532	532
Goodwill	18	16	412	390
Other non-current assets	157	160	288	337
Cash and cash equivalent (Net borrowings)	(59)	(59)	(390)	(390)
Current and non-current liabilities	(114)	(115)	(237)	(264)
Net effects of investments	103	103	750	750
Advances paid in 2021	(16)	(16)
Total purchase price	87	87	750	750

Following the definitive allocation of the 2022 business combinations, financial statements were not restated taking into account the immateriality of the changes.

28 Guarantees, commitments and risks

Guarantees

(€ million)	December 31, 2023	December 31, 2022
Consolidated subsidiaries	7,772	7,082
Unconsolidated subsidiaries	196	202
Joint ventures and associates	9,294	9,802
Others	398	477
	17,660	17,563

Guarantees issued on behalf of consolidated subsidiaries primarily consisted of: (i) autonomous guarantee contracts given to third parties relating to bid bonds and performance bonds for €3,783 million (€3,282 million at December 31, 2022); (ii) autonomous guarantee contracts issued by the Exploration & Production segment primarily in relation to oil & gas activities for €1,096 million (€1,098 million at December 31, 2022); (iii) autonomous guarantee contracts issued to cover the sale of stored gas, gas transportation and potential exposures to the gas system in Italy for €385 million (€388 million at December 31, 2022); (iv) guarantees issued to social security institutes in relation to employee redundancy incentive agreements for €375 million (€205 million at December 31, 2022); (v) guarantees issued towards financial administration for credits VAT refunds for €258 million (€47 million at 31 December 2022). At December 31, 2023, the underlying commitment issued on behalf of consolidated subsidiaries covered by these guarantees was €7,662 million (€7,003 million at December 31, 2022).

Guarantees issued on behalf of joint ventures and associates primarily consisted of: (i) autonomous guarantee contracts given to the Azule Group for €3,055 million (€3,164 million at December 31, 2022) relating to leasing contracts of FPSO vessels to be used as part of the development projects in Angola; (ii) guarantees issued against the contractual commitments undertaken by Vår Energi ASA in relation to Oil&Gas activities for €2,013 million (€2,151 million at 31 December 2022); (iii) autonomous guarantee contracts and other personal guarantees given to third parties relating to bid bonds and performance bonds for €1,397 million (€1,613 million at December 31, 2022) of which €1,327 million (€1,378 million at December 31, 2022) related to guarantees issued towards the contractors who were building a floating vessel for gas liquefaction and exportation (FLNG) as part of the Coral development project offshore Mozambique; (iv) autonomous guarantee contracts issued towards banks and other lending institutions for €1,448 million (€1,499 million at December 31, 2022) in relation to loans and lines of credit received as part of the Coral development project offshore Mozambique with respect to the financing agreements of the project with Export Credit Agencies and banks; (v) autonomous guarantee contracts issued in favor of third parties for the investment in the offshore wind project of Dogger Bank for €1,272 million (€1,259 million at December 31, 2022). At December 31, 2023, the underlying commitment issued on behalf of joint ventures and associates covered by these guarantees was €6,077 million (€6,859 million at December 31, 2022).

As provided by the contract that regulates the petroleum activities in Area 4 offshore Mozambique, Eni SpA in its capacity as parent company of the operator has provided concurrently with the approval of the development plan of the reserves which are located exclusively within the concession area, an irrevocable and unconditional parent company guarantee in respect of any possible claims or any contractual breaches in connection with the petroleum activities to be carried out in the contractual area, including those activities in charge of the special purpose entities like Coral FLNG SA, to the benefit of the Government of Mozambique and third parties. The obligation of the guarantor towards the Government of Mozambique is unlimited (non-quantifiable commitments), whereas they provide a maximum liability of €1,357 million in respect of third-parties claims. This guarantee will be effective until the completion of any decommissioning activity related to both the development plan of Coral as well as any development plan to be executed within Area 4 (particularly the Mamba project). This parent company guarantee issued by Eni covering 100% of the aforementioned obligations was taken over by the other concessionaires (Kogas, Galp and ENH) and by ExxonMobil and CNPC shareholders of the joint venture Mozambique Rovuma Venture SpA, in proportion to their respective participating interest in Area 4.

Guarantees issued on behalf of third parties consisted of: (i) a guarantee issued in favor of Gulf LNG Energy and Gulf LNG Pipeline on behalf of Angola LNG Supply Service Llc to cover contractual commitments of paying re-gasification fees for €184 million (€190 million at December 31, 2022); (ii) the share of the guarantee attributable to the State oil Company of Mozambique ENH, which was assumed by Eni in favor of the consortium financing the construction of the Coral project FLNG vessel for €161 million (€167 million at December 31, 2022). At December 31, 2023, the underlying commitment issued on behalf of third parties covered by these guarantees was €296 million (€323 million at December 31, 2022).

Commitments and risks

	December	December
(€ million)	31, 2023	31, 2022
Commitments	79,513	77,481
Risks	1,140	1,228
	80,653	78,709

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 €73,615 million (€73,334 million at December 31, 2022); (ii) a parent company guarantee of €3,619 million (€3,748 million at December 31, 2022) given 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 setup of ADNOC Global Trading Ltd dedicated to marketing petroleum products. The parent company guarantee still outstanding has been issued to guarantee the obligations set out in the Shareholders Agreements and will remain in force as long as the investment is maintained; (iii) commitments in the Exploration & Production segment for the purchase of Neptune Energy Group Limited ("Neptune") for about €2 billion; (iv) commitments in the Plenitude business line for the purchase of renewable energy projects in Spain, United States and Italy for €107 million (€210 million at December 31, 2022).

Risks relate to potential risks associated with: (i) contractual assurances given to acquirers of certain investments and businesses of Eni for €250 million (€262 million at December 31, 2022); (ii) assets of third parties under the custody of Eni for €879 million (€957 million at December 31, 2022).

Other commitments and risks

A parent company guarantee was issued on behalf of Cardón IV SA (Eni's interest 50%), a joint venture operating the Perla gas field located in Venezuela, for the supply to PDVSA GAS of the volumes of gas produced by the field until the end of the concession agreement (2036). In case of failure on part of the operator to deliver the contractual gas volumes out of production, the claim under the guarantee will be determined by applying the local legislation. Eni's share (50%) of the contractual volumes of gas to be delivered to PDVSA GAS amounted to a total of around €11.4 billion. Notwithstanding this amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued by PDVSA on behalf of Eni for the fulfillment of the purchase commitments of the gas volumes by PDVSA GAS.

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 subjects specialized in forest conservation programs.

On February 5, 2021, EniServizi SpA (EniServizi) signed on behalf of Eni SpA (Eni) an addendum to the lease contract of a property to be built signed in July 2017 between Eni and the management company of the real estate investment fund owner of the new complex construction in San Donato Milanese (the Property), including the postponement of the delivery date of the property from July 28, 2020 to December 31, 2021.

Subsequently, on June 16, 2023, the parties agreed to start the delivery procedures despite the absence of completion (scheduled for April 2024) of one of the car parks adjacent to the real estate complex. The inspections and preparatory controls to the delivery involved a series of activities to remedy defects and substantial discrepancies on the part of the Property to be carried out before delivery and still being completed, with consequent failure to complete the same by December 31, 2023. Eni has therefore applied to the Property the penalties for late delivery provided for in the Contract, supported by first demand sureties for the amount of €16.86 million, equal to approximately €30 million.

In addition, Eni is is exposed to non-quantifiable risks related to contractual guarantees issued in case of certain Eni transactions, including loss of control of subsidiaries and divestment of businesses and investments, 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 matters will not have a material adverse effect on Eni's results of operations and cash flow.

Eni has in place long-term natural gas supply contracts with the Russian company Gazprom. During 2023 supplies to Eni, which has regularly recognized the minimum contractual quantities, were effectively reduced to zero as part of various trade disputes between the parties. Eni, having fulfilled its contractual commitments, expects this situation to continue in 2024 also considering that the external context has not undergone any changes.

Risk factors

The following is the description of financial risks and their management and control. With reference to the issues related to credit risk, the parameters adopted for the determination of expected losses and the estimates of the probability of default and the loss given default 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, 2023, the Company retains liquidity reserves that management deems enough to meet the financial obligations due in the next eighteen months.

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.

$$\text{F-98}$$

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 future cash flows. The Company actively manages market risk in accordance with a set of policies and 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, Eni Finance International SA - merged into Eni SpA in December 2023 - and Banque Eni SA, 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 SpA that are in charge to execute certain activities relating to commodity derivatives. In particular, Eni Corporate finance department (and Eni Finance International SA until the date of the merge) manages subsidiaries' financing requirements, respectively, covering funding requirements and using available surpluses and all the transactions concerning currencies and derivative contracts on interest rates and currencies 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 and brokerage platforms (i.e. SEF), and over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into 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 (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing directly or indirectly related to covered industrial assets, so as 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 policies and 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 limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a predefined time horizon; limits of revision strategy, 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 for interest rate and foreign currency exchange rate risks 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 Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni's guidelines define rules to manage the commodity 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 revision strategy, 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 risk provide for a mechanism of allocation of the Group 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 to face any extraordinary requirement. Eni's finance department, with the aim of optimizing the efficiency and ensuring maximum protection of capital, manages such reserve and its immediate liquidity within the limits assigned. The management of strategic cash 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.

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 foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or 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 departments, which pool Group companies' positions, hedging the Group net exposure by using certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value based on market prices provided by specialized info-providers. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period.

Market risk - Interest rate

Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of net finance charges. Eni's interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in management's "Finance plan". The Group's central departments pool borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with management plan, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 20-day holding period.

Market risk - Commodity

Price risk of commodities is identified as the possibility that fluctuations in the price of materials and basic products produce significant changes in Eni's operating margins, determining an impact on the economic result such as to compromise 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 four-year plan and budget, components not yet under contract but which will be with reasonable certainty (commitment exposure) and the relevant 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/coverage 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 a commercial nature, Eni's risk management target is to optimize the "core" activities and preserve the economic/financial results. Eni manages the commodity risk through the trading units (Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA) and the exposure to commodity prices through the Group's finance departments 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 or, absent market prices, 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 one-day holding period.

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 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 a 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 financial activities and operational boundaries, 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 2023, the rating of the Strategic liquidity investment portfolio was A/A-, in line compared to the end of 2022.

The following tables show amounts in terms of VaR, recorded in 2023 (compared with 2022), relating to interest rate and exchange rate risks in the first section and commodity risk (aggregated by type of exposure). Regarding the management of strategic liquidity, the table reports the sensitivity to changes in interest rate.

(Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

			2023		2022
(€ million)	High	Low	Average	At year end	High	Low	Average	At year end
Interest rate (a)	7.26	0.90	2.30	1.32	9.05	2.61	5.19	3.22
Exchange rate (a)	0.62	0.04	0.21	0.33	0.95	0.09	0.29	0.34

a) Value at risk deriving from interest and exchange rates exposures include the following finance departments: Eni Corporate Finance Department, Eni Finance International SA (incorporated in Eni SpA as of December 2023) and Banque Eni SA.

(Value at risk - Historic simulation method; holding period: 1 day; confidence level: 95%)

	2023				2022
		At year
(€ million)	High	Low	Average	end	High	Low	Average	end
Commercial exposures -
Management Portfolio (a)	257.89	6.38	55.35	6.71	800.39	30.65	261.41	30.65
Trading (b)	1.53	0.05	0.43	0.21	1.63	0.01	0.36	0.04

(a) Refers to Global Gas & LNG Portfolio business area, Power Generation & Marketing, EE-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 year considering 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, EE-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 (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston).

(Sensitivity - Dollar value of 1 basis point - DVBP)

	2023				2022
				At year				At year
(€ million)	High	Low	Average	end	High	Low	Average	end
Strategic liquidity - € Portfolio (a)	0.22	0.13	0.18	0.19	0.30	0.16	0.23	0.16

(a) Management of strategic liquidity portfolio starting from July 2013.

(Sensitivity - Dollar value of 1 basis point - DVBP)

		2023		2022
				At year				At year
(\$ million)	High	Low	Average	end	High	Low	Average	end
Strategic liquidity - US dollar
Portfolio (b)	0.12	0.04	0.08	0.11	0.13	0.04	0.08	0.04

(a) Management of strategic liquidity portfolio in US dollar currency starting from August 2017.

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. 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 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 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

With regard to credit risk arising from financial counterparties deriving from current and strategic use of liquidity, derivative contracts and transactions with underlying financial assets valued at fair value, Eni has established internal policies providing exposure control and concentration through maximum credit risk limits corresponding to different classes of financial counterparties defined by the Company's Board of Directors and based on ratings provided for by primary credit rating agencies. Credit risk arising from financial counterparties is managed by the Eni's operating finance departments, Eni Global Energy Markets SpA, Eni Trade & Biofuels SpA and Eni Trading & Shipping Inc specifically for commodity derivatives transactions, as well as by companies and business areas limitedly to physical transactions with financial counterparties, consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored by each counterpart and by group of belonging 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, or the Group is unable to sell its assets in the marketplace in order to meet short-term finance requirements and to settle obligations. 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 lines of credit and the access to a wide range of funding opportunities which can be activated through the credit system and capital markets. Due to the continuing volatility of commodity markets and the related financial commitment linked to the margin of commodity derivatives, Eni has consolidated its higher financial flexibility achieved in the last year through the activation of liquidity swaps in addition to new financing lines acquired. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €16.8 billion were drawn as of December 31, 2023. The Group has credit ratings of A- outlook Stable and A-2, respectively, for long and short-term debt, assigned by Standard & Poor's; Baa1 outlook Stable and P-2, respectively, for long and short-term debt, assigned by Moody's; A- outlook Stable and F1, respectively for long and shortterm debt, assigned by Fitch. Eni's credit rating is linked, in addition to the Company's industrial fundamentals and trends in the trading environment, to the sovereign credit rating of Italy. Based on the methodologies used by the credit rating agencies, a downgrade of Italy's credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. During 2023, Moody's revised Eni's outlook from Negative to Stable, due to the improvement in the Italian outlook.

During 2023 Eni renegotiated and expanded its portfolio of committed credit lines through the stipulation of a sustainability-linked bond facility agreed with a pool of banks for €3.0 billion. At December 31, 2023 available committed borrowing facilities amounted to €9.1 billion.

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)	2024	2025	2026	2027	2028	2029 and thereafter	Total
December 31, 2023
Non-current financial liabilities
(including the current portion)	3,340	2,689	3,219	2,611	5,520	7,780	25,159
Current financial liabilities	4,092						4,092
Lease liabilities	1,120	691	476	399	364	2,270	5,320
Fair value of derivative instruments	2,414	21	40	5	37	50	2,567
	10,966	3,401	3,735	3,015	5,921	10,100	37,138
Interest on finance debt	738	676	572	496	389	804	3,675
Interest on lease liabilities	269	221	188	167	148	668	1,661
	1,007	897	760	663	537	1,472	5,336
Financial guarantees	1,114						1,114

	Maturity year
(€ million)	2023	2024	2025	2026	2027	2028 and thereafter	Total
December 31, 2022
Non-current financial liabilities
(including the current portion)	2,883	2,339	2,640	3,298	1,927	9,246	22,333
Current financial liabilities	4,446						4,446
Lease liabilities	851	584	445	365	347	2,312	4,904
Fair value of derivative instruments	9,042	1	51	54		180	9,328
	17,222	2,924	3,136	3,717	2,274	11,738	41,011
Interest on finance debt	590	494	459	365	284	716	2,908
Interest on lease liabilities	235	209	184	165	147	685	1,625
	825	703	643	530	431	1,401	4,533
Financial guarantees	1,668						1,668

Liabilities for leased assets including interest charges for €741 million (€760 million at December 31, 2022) 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 table below presents the timing of the expenditures for trade and other payables.

	Maturity year
		2029 and
(€ million)	2024	2025 - 2028	thereafter	Total
December 31, 2023
Trade payables	14,231			14,231
Other payables and advances	6,423	50	104	6,577
	20,654	50	104	20,808

		Maturity year
			2028 and
(€ million)	2023	2024 - 2027	thereafter	Total
December 31, 2022
Trade payables	19,527			19,527
Other payables and advances	6,182	77	110	6,369
	25,709	77	110	25,896

Expected payments under contractual obligations ²⁵

In addition to lease, financial, trade and other liabilities represented in the balance sheet, the Company is subject to noncancellable 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 four-year industrial plan approved by the Company's management and for subsequent years on the basis of management's long-term assumptions.

²⁵Contractual obligations related to employee benefits are indicated in note 22 - Provisions for employee benefits.

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 2024 for decommissioning oil & gas assets and for environmental clean-up and remediation are based on management's estimates and do not represent financial obligations at the closing date.

	Maturity year
(€ million)	2024	2025	2026	2027	2028	2029 and thereafter	Total
Decommissioning liabilities (a)	679	497	468	482	968	10,912	14,006
Environmental liabilities	646	495	399	368	305	1,406	3,619
Purchase obligations (b)	21,032	18,024	17,887	14,800	12,519	66,415	150,677
- Gas
. take-or-pay contracts	17,904	17,286	17,358	14,463	12,330	65,919	145,260
. ship-or-pay contracts	750	540	475	327	186	469	2,747
- Other purchase obligations	2,378	198	54	10	3	27	2,670
Other obligations	4	14	2				20
- Memorandum of intent - Val
d'Agri	4	14	2				20
Total (c)	22,361	19,030	18,756	15,650	13,792	78,733	168,322

(a) Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.

(b) Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The take-or-pay contracts wit Gazprom are disclosed in "Other commitments and risks" section.

(c) Expected payments under contractual obligations comprises obligations of the subsidiaries held for sale for €552 million.

Capital investment and capital expenditure commitments

In the next four years, Eni expects capital investments and capital expenditures of €35 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)	2024	2025	2026	2027	2028 and thereafter	Total
Committed projects	7,655	7,023	3,562	2,075	7,048	27,363

Other information about financial instruments

	2023			2022
	Income (expense) recognized in			Income (expense) recognized in
(€ million)	Carrying amount	Profit and loss account	OCI	Carrying amount	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)	6,782	284		8,251	(55)
Non-hedging and trading derivatives (b)	837	417		2,006	(1,723)
Other investments valued at fair value (c)	1,256	255	45	1,202	351	56
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other (d)	17,054	(285)		21,396	31
Financing receivables (e)	3,163	141		3,415	(16)
Securities (a)	61	1		56
Trade payables and other (a)	20,808	69		25,897	53
Financing payables (f)	28,729	(734)		26,917	(692)
Net assets (liabilities) for hedging derivatives (g)	(35)	(442)	541	(129)	(4,677)	794

(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 €478 million (loss for €1,736 million in 2022) and as loss within "Finance income (expense)" for €61 million (income for €13 million in 2022).

(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 €249 million (net reversals for €47 million in 2022) and as expense within "Finance income (expense)" for €36 million (expense for €16 million in 2022), including interest income calculated on the basis of the effective interest rate of €15 million (same amount in 2022).
• (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 €144 million (interest income for €86 million in 2022) and net impairments for €6 million (net impairments for €111 million in 2022).
• (f) In the profit and loss account, income or expense were recognized within "Finance income (expense)", including interest expense calculated on the basis of the effective interest rate of €743 million (interest expense for €568 million in 2022).
• (g) In the profit and loss account, income or expense were recognized within "Sales from operations" and "Purchase, services and other".

Disclosures about the offsetting of financial instruments

	Gross amount of financial	Gross amount of financial assets and liabilities	Net amount of financial
(€ million)	assets and liabilities	subject to offsetting	assets and liabilities
December 31, 2023
Financial assets
Trade and other receivables	19,936	3,385	16,551
Other current assets	8,525	2,888	5,637
Other non-current assets	3,400	7	3,393
Financial liabilities
Trade and other liabilities	24,039	3,385	20,654
Other current liabilities	8,467	2,888	5,579
Other non-current liabilities	4,103	7	4,096
December 31, 2022
Financial assets
Trade and other receivables	23,546	2,706	20,840
Other current assets	18,684	5,863	12,821
Other non-current assets	2,236		2,236
Financial liabilities
Trade and other liabilities	28,415	2,706	25,709
Other current liabilities	18,336	5,863	12,473
Other non-current liabilities	3,234		3,234

The offsetting of financial assets and liabilities related to: (i) receivables and payables pertaining to the Exploration & Production segment towards state entities for €3,385 million (€2,651 million at December 31, 2022) and trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €55 million at December 31, 2022; (ii) other current and non-current assets and liabilities for derivative financial instruments of €2,895 million (€5,863 million at December 31, 2022).

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 believes a negative outcome to be unlikely 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 – Crotone omitted clean-up. In April 2017, the Public Prosecutor of Crotone initiated a criminal case relating to reclamation activities at the Crotone site. Meanwhile, the new clean-up project presented by the Company POB phase 2 was approved by the Italian Ministry for the Environment. By a court order of January 10, 2022, the judge of the preliminary hearing of Crotone ordered the performing of an independent technical assessment on the environmental status of the site which ascertained that Eni Rewind had carried out the environmental activities in its own areas in compliance with the granted authorizations. A decision of the Public Prosecutor is awaiting following the filing of this supplementary consultancy.

(ii) Eni Rewind SpA - Illegal landfill in Minciaredda area, Porto Torres site. In 2015, the Public Prosecutor of Sassari had 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 the natural persons allegedly liable of the 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.

(iii) 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. The Gela Refinery 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. At the closing of the preliminary investigation, the Public Prosecutor of Gela merged into this proceeding 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. The proceeding is still ongoing.

(iv) 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 a full compliance of the plant and the industrial process with the requirements of the applicable laws, as well as with best available technologies and international best 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. The appeal proceedings are underway.

(v) 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 was 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 subsequent to 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, rejecting the request of the Public Prosecutor for qualifying the alleged crime as a new type of legal offence (environmental disaster). In the context of this proceeding, 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, considering that another request for summons to the proceedings brought by the Public Prosecutor was once again rejected, the defense has filed a request for the dismissal of the dispute.

As regards, the Company as an entity pursuant to Legislative Decree No. 231/01, considering that another request for summons to the proceedings brought by the Public Prosecutor was once again rejected, the defense has filed a request for the dismissal of the dispute. The Public Prosecutor, however, issued a new request for indictment and a preliminary hearing has been set for next May 2024.

(vi) 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 is in progress before the Court of Agrigento, to which the proceeding has been transferred due to territorial jurisdiction.

(vii) 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 offenses of 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.

(viii) 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.

Similar allegations were charged against other employees of the companies co-located at the industrial hub of Priolo Gargallo as well as of IAS SpA, while 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 Constitutional Court about the legitimacy of a governmental decree that granted ISAB, one of the companies operating at the Priolo vertically integrated petrochemical complex, certain measures intended to preserve the continuity of the production activity. Versalis therefore appeared before the Constitutional Court, which set the relevant hearing for May 2024. In the meantime, the proceeding remains pending under investigation.

(ix) Eni SpA - Fatal accident Ancona offshore platform. On March 5, 2019, a fatal accident occurred at the Barbara F platform offshore of Ancona that resulted in the death of an Eni employee and the injury of two contractors. Two contract workers and the family of the Eni employee were all fully compensated. As part of the technical assessment of the incident, the Public Prosecutor of Ancona resolved to put under investigation two Eni employees. Also, the Company has been put under investigation as entity liable pursuant to Legislative Decree No. 231/01, and two employees of the contractor company engaged in the work. At the outcome of the preliminary hearing, the Judge ordered the indictment for all the defendants and Eni. The proceeding is currently pending in the preliminary hearing phase.

(x) Raffineria di Gela SpA and Eni Rewind SpA - Groundwater pollution survey and reclamation process of the Gela site. Following complaints made by former contractors, the Public Prosecutor of Gela commenced a proceeding for allegations of environmental pollution, omitted clean-up, negligent personal injury and illegal waste management in the area of the Gela refinery, as part of the execution of clean-up of soil and groundwater as well as decommissioning activities in the area currently managed by Eni Rewind SpA, also on behalf of the companies Raffineria di Gela SpA, ISAF SpA (in liquidation) and Versalis SpA with respect to the efficiency and efficacy of the barrier system. The Public Prosecutor carried out various checks and investigations, and then proceeded with a preventive seizure, with reference to the plants used for the remediation of the site's underground water currently managed by Eni Rewind as well as the plant areas intended for the implementation of the groundwater remediation project. A judicial administrator was appointed to manage those facilities.

The judicial administrator filed an initial technical report in which he confirmed that the clean-up activities were being executed in compliance with the legislation and with a series of implementation improvements by the company in agreement with other parties in charge. The Public Prosecutor's Office also issued the summons decree, and the proceeding is now pending in the hearing phase.

(xi) 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 the 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 abovementioned companies, with the exception of a former employee of Versalis and of two Edison employees. The proceeding is pending on the trial phase.

(xii) 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.

(xiii) Eni SpA R&M Refinery of Livorno - Criminal proceedings for incidents at work. On October 20, 2020, a notice was served at the Livorno refinery for Eni as entity subjected to preliminary investigations in the context of a criminal proceeding pending before the Public Prosecutor's Office of Livorno, in relation to an accident at work occurred in summer of 2019 at an electrical substation of the Refinery and as consequence two employees were injured. The company provided compensation to the employee who suffered the consequences of the accident. The allegation is of aggravated personal injury while the Company is accused of being the entity liable pursuant to Legislative Decree No. 231/01.

In September 2021, the Public Prosecutor's Office issued a notice of conclusion of the preliminary investigations. Subsequently, the summons order was notified.

Following the outcome of the first level of judgement, on March 12, 2024, the Court issued a sentence of acquittal of the accused natural persons and of Eni SpA pursuant to Legislative Decree. 231/01. Eni is awaiting the filing of the reasons for the sentence.

(xiv) 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.

(xv) 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 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 proceeding is currently pending preliminary investigations, with three unrepeatable technical investigations underway.

(xvi) Eni SpA - Pomezia depot – Involuntary environmental pollution. A criminal proceeding is ongoing concerning an alleged crime of pollution of the 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 contaminations at the tanks. As a result of these assessments, two Eni 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. The proceeding is pending at the preliminary hearing stage.

1.2 Civil and administrative proceedings in the matters of environment, health and safety

(i) Kazakhstan disputes. Eni along with its co-venturers is currently party to several disputes with the Republic of Kazakhstan, involving environmental matters, in relation to a sulfur permitting inspection outcome, cost recovery claims under applicable production sharing contracts and other issues. In March 2023, the Republic of Kazakhstan appointed its arbitrator in each of the disputes, formally starting the arbitration process. At the beginning of April 2024, the Republic has filed its statements of claims. Eni is in the process of assessing the merits of the Republic's claims and accordingly, at this time, it is not possible to reliably estimate the outcomes.

(ii) 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 carry out emergency safety activities with the removal of sediments 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 about the environmental responsibility of the companies colocated at the Priolo hub with respect to the pollution of the harbor and warned them against carrying out unauthorized 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 basing on updated environmental data. The Eni's subsidiary also commenced activities to identify the persons responsible of 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 the 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.

(iii) Eni SpA – Eni Rewind SpA – Priolo – Malformation civil lawsuits. In February 2022 Eni Rewind was sued before the Court of Syracuse for compensation for damages (€800,000 for each of the plaintiffs) by two citizens of Augusta (SR), who claimed to have been born with serious malformations due to spills of mercury from the chlor-soda plant in Priolo.

Eni Rewind filed an appearance in court filing a claim and indemnification against Edison, taking into account that the chlor- soda plant was received by Eni group as part of the Enimont transaction, therefore in a period following the alleged exposure to the mercury by the actors, which necessarily occurred between the years of birth 1972 and 1975. Following the incorporation of Edison SpA and the celebration of the respective hearings, the two proceedings are currently in the preliminary investigation phase.

(iv) Eni SpA – Eni Rewind SpA – Raffineria di Gela SpA – Claim for preventive technical inquiry and judgments on the merits. In February 2012, Eni's subsidiaries Raffineria di Gela SpA and Eni Rewind SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified of a claim issued by the parents of children with birth defects in the Municipality of Gela between 1992 and 2007. The claim called for an inquiry aimed at determining any causality between the birth defects suffered by these children and any environmental pollution caused by the Gela site, quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. The same issue was the subject of previous criminal proceedings, of which one closed without determining any illegal behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. In December 2015, the three companies involved were sued in relation to a total of 30 cases of compensation for damages in civil proceedings. In May 2018, the Court issued a first instance judgment concerning one case. The Judge rejected the claim for damages, acknowledging the arguments of the defendant companies in relation to the absence of evidence concerning the existence of a causal link between the birth defects and the alleged industrial pollution. The judgment has been appealed by the claimants.

In June 2021 the Civil Court of Gela issued a second judgment rejecting the claim for compensation, recognizing the validity of the arguments of the defendant companies regarding the lack of evidence on the existence of a cause between the pathology and the alleged industrial pollution. The counterparties filed an appeal.

In relation to the first appeal promoted against the first ruling of the Court of Gela, the First Instance Court of Caltanissetta rejected the appeal proposed and accepted the one proposed incidentally by the Eni companies involved, concerning the regulation of litigation costs relating to the first instance proceedings and the reported incorrectness of the compensation made therein since the legal requirements were not met. The counterparty appealed to the Third Instance Court.

(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 extrajudicial settlement, fixing a deadline to present further proposals on the matter.

The parties did not adhere to the conciliatory proposal. The proceeding is underway.

(vi) Eni SpA Eni Oil&Gas Inc - Climate change. Between 2017 and 2018, seven lawsuits were brought in the California state court by local government authorities and a fishermen's association against Eni SpA, a subsidiary (Eni Oil & Gas Inc.) and several other companies, aimed at obtaining compensation for damages attributable to the increase in sea level and temperature as well as to hydrogeological instability.

These proceedings, initially brought before the state court, were subsequently transferred to the federal court at the request of the defendants, who filed a specific request noting the lack of jurisdiction of the State Courts In 2019, the Federal court sent the cases back to the state court.

The defendants then appealed to the Ninth Circuit, challenging the referral order. All proceedings have been suspended pending the appeal hearing before the Ninth Circuit.

Following a complex and long procedural process, during the summer of 2023, the proceedings were definitively assigned to the state court of California. In June 2023 Eni SpA and Eni Oil & Gas Inc. presented together with the other defendant companies without registered office in California a joint motion to suppress to contest the jurisdiction of California, on the assumption of never having had relevant contacts with that State and therefore there is a shortage of so-called personal jurisdiction. In November 2023, the plaintiffs presented a petition for coordination aimed at bringing together the preliminary phases of the proceedings before a single state court.

On December 14, 2023, the fishermen's association that had promoted one of the disputes voluntarily renounced the case. On January 25, 2024, the competent judge accepted the petition for coordination and recommended that of San Francisco as the deciding state court. A first Case Management Conference will be held on April 4, 2024.

(vii) 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 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 the 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 proceeding is underway.

(viii) 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.

On September 21, 2023, Eni promptly filed its statement of appearance and response in Court, accompanied by a technical report, objecting to the inadmissibility, untenability and total unfoundedness of the plaintiffs' claims. In the subsequent proceedings of January 5, 26 and February 6, 2024, the Parties filed further briefs and documents, taking a position on the opposing defenses. The first hearing of the case (with formal proceedings as requested by the Judge) was held on January 16, 2024. The judge reserved his rights on the requests proposed by the Parties. The decision is pending.

(ix) 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.

2. Proceedings concerning criminal/administrative corporate responsibility

(i) OPL 245 Nigeria. In relation to the stipulation between Eni, the Government of the Federal Republic of Nigeria "FGN" and another international oil company of the Resolution Agreement of April 29, 2011 relating to the "Oil Prospecting Licence" of the offshore field identified in block 245, several investigations had been opened by the judicial authorities of Italy, UK and Nigeria concerning alleged crimes in the assignment of the block, including the crime of international corruption. The investigations involved some top managers of Eni and of the Company itself pursuant to Legislative Decree no. 231/01. Eni basing also on the findings of an internal review of the case performed by an independent US legal consultant appointed by the Company's board of statutory auditors and by the Watch body considered the accusations groundless. The US Department of Justice carried out its own inquiry basing on the US FCPA and dismissed the case without any liability in 2019. The UK prosecutors dismissed the case due to lack of jurisdiction.

The proceeding in Italy established by the Public Prosecutor of Milan, which had requested the indictment of the Eni managers involved and of the Company, was resolved in a manner totally favorable to Eni with a sentence of acquittal for all the defendants because the fact did not exist. The appeal proceedings, promoted by the First Instance public prosecutors, and by the FGN as civil party, concluded during 2022, reaffirming the first instance acquittal sentence which therefore became final.

Finally, FGN, which in 2023 had promoted an appeal to the Third Instance Court against the ruling of the Court of Milan, requesting its annulment with referral to the competent civil judge for the sole purpose of civil rulings and damage compensation, withdrew the appeal to the Third Instance Court, as it was inferred from a letter signed by the Attorney General transmitted after two hearings of the ICSID arbitration held in London. This arbitration was promoted by Eni after the acquittal sentence to protect the investment, requesting the forced conversion of the exploration license (OPL 245) into an extractive license (OML) as well as \$700 million in damages for the mere delay (in addition to a reserve for possible damages). On January 20, 2020, Eni's subsidiary in Nigeria ("NAE") was notified of the beginning of a new criminal case before the Federal High Court of Abuja.

The proceeding, mainly focused on the accusations against Nigerian individuals (including the Minister of Justice in office in 2011, at the time of the disputed facts), has involved NAE and Shell Nigeria Exploration and Production Company Limited ("SNEPCO") as co-holders of the OPL 245 license. These Nigerian individuals were accused in 2011 of illicit corruption, which NAE and SNEPCO allegedly unlawfully facilitated. The beginning of the trial, originally scheduled for the end of March 2020, was postponed as a result of the closure of judicial offices in Nigeria due to the COVID-19 emergency and resumed at the beginning of 2021. During the proceedings, several witnesses were heard, mainly summoned at the request of the "Economic and Financial Crimes Commission" ("EFCC"). Considering the weakness of the evidence produced by the EFCC, the defendants presented a request for a declaration of no need to proceed, which the EFCC did not oppose, at least for the part relating to the accusations made against NAE, SNEPCO and the Minister of Justice. The proceeding is underway.

3. Other proceedings concerning criminal matters

(i) Eni SpA (R&M) – Taranto Refinery - Criminal proceedings for breach of excise assessment. The proceeding relates to the alleged lack of tax assessment of an energy product moved, under excise duty suspension, from a tank of the Taranto refinery.

At the end of the preliminary investigation phase, the former manager of the refinery and three other employees resulted under investigation for an alleged continued hypothesis of subtraction from the assessment of excise duties, due to multiple movements that took place in the period from June 30 to September 9, 2021, from the tank under investigation, the meter of which has been seized since October 13, 2021. The proceeding is underway.

(ii) Enimed SpA – Criminal proceedings for alleged evasion of payment of the excise duty on flux products. The criminal case originates from an investigation by the financial police of Ragusa which led to the verification in May 2020 of a series of incidents of theft of flux - an energy product used in suspension of excise duty - stolen directly from Enimed pipelines by arrested third parties flagrantly. Following these facts, the same police started a verification on the accounting methods for the flux by the Company in the period 2018-2020. As a result, the Company was accused of irregularities in the management of the diesel flux with alleged subtractions of indirect taxes (excise duties and VAT) equal to approximately €50 million. The competent Public Prosecutor's Office (Gela) for its part has promoted proceedings against the former CEO of Enimed (for the years 2018 - 2020) for the crime evading the payment of excise duties on energy products. The criminal proceedings were extended to two other Enimed employees for the same crime. As part of the same proceeding, third parties are being prosecuted for theft of flux, a hypothesis which instead sees Enimed identified as plaintiff. The proceeding is underway.

4. Tax proceedings

(i) Dispute for omitted payment of a property tax for some oil offshore platforms located in territorial waters. Tax disputes are pending with some Italian local authorities regarding whether oil and gas offshore platforms located within territorial boundaries should be subject to a property tax in the period 2016-2019.

In 2016 the tax regulatory framework changed due to enactment of law no. 208/2015, which excluded from the scope of the property tax the value of plants instrumental to specific production processes. In addition, the Finance Department recognized that offshore platforms met the requirements for classification as instrumental plants and consequently are excluded from the scope of the property tax (resolution no. 3 of June 1, 2016). Based on this interpretation, Eni did not pay any property tax for the years 2016- 2019. However, the ruling of the Department of Finance is not binding for local authorities with taxing powers as recognized by the Third Instance Court and some of these have issued assessment notices for 2016-2019. The Company filed an appeal against these notices. Although Eni believes that oil platforms located in the territorial sea should be excluded from the tax base of the property tax on the base of the interpretation of the law in the light of the resolution of the Department of Finance, having assessed the risks of losing in pending disputes, the Company accrued a risk provision, the amount of which excludes fines since Eni's conduct was based on the administrative resolution, as well as taking into account the reduction of the tax base excluding the "plant component" as provided by the law. The proceeding is still ongoing.

Law Decree 124/19 (enacted with Law 157/19) has established, starting from 2020, that marine platforms are subject to a new property tax that will replace and supersede any other ordinary local property tax eventually levied on these plants up to 2019. This rule has therefore sanctioned, starting from 2020, the existence of the tax requirement for these plants.

5. Settled proceedings

(i) Eni Rewind SpA (company incorporating EniChem Agricoltura SpA — Agricoltura SpA in liquidation — EniChem Augusta Industriale Srl — Fosfotec Srl) — Proceeding about the industrial site of Crotone. In 2010 a criminal proceeding started before the Public Prosecutor of Crotone relating to allegations of environmental disaster, poisoning of substances used in the food chain and omitted clean-up due to the activity at a landfill site which was taken over by Eni in 1991.

The defendants were certain managers of Eni Group companies, who have managed the landfill since 1991. At the preliminary hearing of July 1, 2020, the Court acquitted all the defendants, some for not having committed the alleged crime and others for expiration of the statute of limitations. The Company has decided to appeal the decision to obtain an acquittal on the merits. Since the appeal has not been counterclaimed by the Public Prosecutor, the expected sentence by the Court can only be reformed in a way that is more favorable to the claimants.

(ii) Environmental claim relating to the Municipality of Cengio. In 2008 the Italian Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio summoned Eni's subsidiary Eni Rewind claiming compensation for the environmental damage relating to the site of Cengio.

The Court of Genoa where the proceeding was established dismissed the environmental liability of Eni Rewind, which took over the industrial hub from Enimont in 1989/1990, because no further environmental degradation had been ascertained since then and because Eni Rewind could not be held liable for the environmental pollution made by its predecessor. In 2023, accepting the invitation by the Second Instance Court, the parties reached a settlement agreement that provided the award of a lump sum of €8 million to the Ministry and the recognition by the Ministry of the adequacy of the works already carried out by the Company to achieve full environmental restoration and complete relief from any environmental damage. The registration of the settlement agreement was completed and the Second Instance Court of Genoa ordered the termination of the proceedings.

(iii) Eni SpA — Court of Milan — Criminal proceeding no. 4659/2023. In February 2018, the Prosecutor of Milan commenced a criminal proceeding in relation to allegations of associative crimes for slandering and reporting false information to a Public Prosecutor, with the aim to interfere with the judicial activity in certain criminal proceedings involving, among others, Eni and some of its directors and managers. Among the natural persons under investigation, there was a former external lawyer and a former Eni manager, at the time of the facts holding a strategic position within the Company. The prosecutors seized relevant documentation and evidence at Eni's offices on several occasions, and the Company's control bodies performed independent internal audits of the matter with the support of external consultants.

In May and June 2019, as part of the same proceeding, the Public Prosecutor's Office of Milan notified Eni and three subsidiaries (ETS SpA, Versalis SpA, Ecofuel SpA) of several requests for documentation. At the same time, in May 2019, Eni was notified of being investigated with reference to the crime 25 decies of Legislative Decree 231/01 for the crime referred to in the art. 377 bis of the criminal code (inducement to not make statements or to make false statements to the judicial authority).

During 2020, a search decree was notified, with simultaneous notice of investigation, to the Eni Chief Services & Stakeholder Relations Officer, the Senior Vice President for Security and a manager of the legal department. Subsequently, the Company was informed of the notification to its Chief Executive Officer of a notice of unrepeatable technical investigations, with contextual notice of investigation aimed at allowing participation, through its technical consultant, in the scheduled technical operations of analysis of the contents of a phone device seized from a former Eni employee.

Following the conclusion of the complex investigation phase, Eni SpA itself, the Chief Executive Officer, the Human Capital Director & Procurement Coordination and the Senior Vice President for Security and, were judged to be uninvolved in the matter.

The positions of Eni SpA itself, the CEO, the Director Human Capital & Procurement Coordination and the Head of Security of Eni Spa were therefore dismissed from the case. The Judge of the preliminary hearing also requested the dismissal of the charges for corruption between private individuals relating to Eni representatives and some external lawyers.

The dismissal decree of Eni SpA defined that the alleged inducement to make false statements by Vincenzo Armanna in the context of the criminal proceeding "OPL 245" was based solely on personal statements (Mr. Amara, Mr. Armanna and Mr. Calafiore) who lacked independence and whose statements had been proved to be groundless. Therefore, their statements were found to be false, leading to the indictment of the aforementioned natural persons due to the statements made against the Chief Executive Officer and the Human Capital Director & Procurement Coordination of the Company.

Following the preliminary hearing, Eni Trading & Shipping in liquidation has finalized the agreement with the Prosecutor's Office on the application of the administrative sanction (so-called plea bargaining) for the offense referred to in the articles. 5, paragraph 1), letter a) 25 octies of Legislative Decree 231/2001.

The criminal proceeding is currently in the first instance hearing phase. Eni, the CEO, the Director Human Capital & Procurement Coordination and two other Eni managers are offended persons for the slander crimes committed against them. Eni is also civilly liable for two charges.

(iv) Eni SpA (R&M) — Criminal proceedings on fuel excise tax. A criminal proceeding was definitely settled, which had been established by the Public Prosecutor of Rome in relation to alleged evasion of excise taxes in the context of retail sales in the fuel market in 2014. This proceeding, where Eni was an offended party, derived from unitization of three distinct investigations: (i) a first proceeding, opened by the Public Prosecutor's Office of Frosinone involved a third company (Turrizziani Petroli) purchaser of Eni's fuel. This investigation was subsequently extended to Eni; (ii) a second proceeding concerning an investigation by the Public Prosecutor's Office of Prato, commenced in regard to the storage hub of Calenzano and related to theft of fuel through manipulation of the fuel dispensers, subsequently extended also to the Refinery of Stagno (Livorno); (iii) a third proceeding, opened by the Public Prosecutor's Office of Rome, concerned alleged missing payment of excise tax on the surplus of the unloading products, as the quantity of such products was larger than the quantity reported in the supporting fiscal documents.

The Public Prosecutor of Rome claimed the existence of an alleged criminal conspiracy aimed at recurring theft of oil products at all of the 22 storage sites which were operated by Eni in Italy. A complex investigation activity was conducted by the Public Prosecutor, leading to the seizure of some equipment used to measure volumes supplied to the markets. Eni was fully cooperating with the Prosecutor and thanks to its commitments obtained the revocation of the seizure measure so as to avoid shutting down production facilities.

In September 2018, Eni received, as an injured party, the notification of the schedule of hearing issued by the Court of Rome, in relation to criminal association and other minor claims, against several natural persons under investigation including over forty Eni's former and current employees — subject of a separate proceeding. After several procedural steps, finally during a preliminary hearing held in December 2019, a sentence to dismiss the case in relation to the association crime was issued for all the defendants.

During 2019, in relation to tax amounts claimed by fiscal authorities, a settlement was reached, and Eni made the payments for the higher excise duties and other taxes for which it was not possible to find the relevant records and book entries.

Finally, at the hearing of January 31, 2023, the Monocratic Court of Rome issued an acquittal sentence for all defendants, former and current Eni's employees, for lack of evidence or acknowledging the statute of limitations in relation to the alleged tax evasion crimes.

(v) Eni SpA - Health investigation related to the COVA center. Beside the criminal proceeding for illegal trafficking of waste, the Public Prosecutor of Potenza started another investigation in relation to alleged health violations concerning the preparation of a Risk Assessment Document of the working conditions at the Val d'Agri Oil Center (COVA). The Public Prosecutor requested the formal opening of an investigation with respect to nine people in relation to the alleged violations.

The technical assessments conducted on behalf of Eni by international experts have ascertained the absence of any risk deriving from the COVA activity for the local population and for its employees. The proceeding was ultimately dismissed by the judge for preliminary investigations, in accordance with the request presented by the prosecuting Public Prosecutor.

(vi) Eni Rewind SpA — The Phosphate deposit at Porto Torres site. In 2015, the Public Prosecutor of Sassari commenced a criminal proceeding in relation to alleged crimes of environmental disaster, unauthorized disposal of hazardous wastes and other environmental crimes in relation to activities performed at the area of "Palte Fosfatiche" (phosphates deposit) located in the Porto Torres hub managed by Eni's subsidiary Eni Rewind SpA, Eni Rewind SpA was investigated pursuant to Legislative Decree No. 231/01 stating the liability of legal entities. Then, Eni Rewind having been duly authorized performed certain works to improve the environmental status of the area under judgement.

The proceedings concluded on July 7, 2023, with a sentence of acquittal of the three managers of Eni Rewind in relation to the crime of environmental disaster, while the Company was discharged of any liability due to the expiry of the statute of limitations. The acquittal sentence has become final.

(vii) Eni Rewind SpA and Versalis SpA — Porto Torres dock. In 2012, the Public Prosecutor of Sassari initiated a criminal case for alleged environmental disaster relating to the malfunctioning of the hydraulic barrier of Porto Torres site (ran by Eni Rewind SpA). Eni Rewind and Versalis were notified that its chief executive officers and certain other managers were being investigated. The Public Prosecutor of the Municipality of Sassari requested that these individuals stand trial. The plaintiffs, the Ministry for Environment and the Sardinia Region claimed environmental damage in an amount of €1.5 billion. Other parties referred to the judge's equitable assessment. At a hearing in July 2016, the court acquitted all defendants of Eni Rewind and Versalis with respect to the crimes of environmental disaster. Three Eni Rewind managers were found guilty of environmental disaster relating to the period limited to August 2010 — January 2011 and sentenced to one-year prison, with a suspended sentence. Eni Rewind filed an appeal against this decision. The subsequent stages of judgment were concluded with the hearing on March 16, 2023, in which the Third Instance Court rejected the appeals and confirmed the first-instance sentence of one year in prison - with the benefit of conditional suspension - against a former manager and two former employees of Eni Rewind in relation to the alleged crimes. The Court also confirmed the general sentence of the three defendants to compensate for the damage suffered by the plaintiffs, to be paid in a separate civil judgment, awarding the claimants just a small provisional amount.

Assets under concession arrangements

Eni operates under concession arrangements mainly in the Exploration & Production segment and the Enilive and Refining 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 the 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 and Refining 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 and liabilities in future years in connection with environmental matters due to: (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. 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 2023, 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 16.03 million tonnes, Eni was awarded free emission allowances of 4.48 million tonnes, determining a deficit of 11.50 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market.

29 Revenues and other income

Sales from operations

	Exploration &	Global Gas & LNG	Enilive, Refining and	Plenitude	Corporate and Other
(€ million)	Production	Portfolio	Chemicals	& Power	activities	Total
2023
Sales from operations	10,843	16,910	52,165	13,598	201	93,717
Products sales and service revenues
Sales of crude oil	3,632		22,053			25,685
Sales of oil products	1,081		24,427			25,508
Sales of natural gas and LNG	5,858	16,638	23	4,431		26,950
Sales of petrochemical products			4,385			4,385
Sales of power				7,252		7,252
Sales of other products	44	23	333	106	3	509
Services	228	249	944	1,809	198	3,428
Products sales and service revenues	10,843	16,910	52,165	13,598	201	93,717
Transfer of goods/services
Goods/Services transferred in a specific moment	10,526	16,825	51,892	13,598	64	92,905
Goods/Services transferred over a period of time	317	85	273		137	812
2022
Sales from operations	12,889	41,230	58,470	19,726	197	132,512
Products sales and service revenues
Sales of crude oil	5,438		20,839			26,277
Sales of oil products	1,070		29,700			30,770
Sales of natural gas and LNG	6,108	40,840	65	5,571		52,584
Sales of petrochemical products			6,241		3	6,244
Sales of power				12,448		12,448
Sales of other products	68		411	223	2	704
Services	205	390	1,214	1,484	192	3,485
Products sales and service revenues	12,889	41,230	58,470	19,726	197	132,512
Transfer of goods/services
Goods/Services transferred in a specific moment	12,585	41,047	58,145	19,599	65	131,441
Goods/Services transferred over a period of time	304	183	325	127	132	1,071
2021
Sales from operations	8,846	16,973	40,051	10,517	188	76,575
Products sales and service revenues
Sales of crude oil	3,573		14,710			18,283
Sales of oil products	885		18,739			19,624
Sales of natural gas and LNG	4,122	16,608	34	3,245		24,009
Sales of petrochemical products			5,652		7	5,659
Sales of power				5,104		5,104
Sales of other products	40	6	132	212	1	391
Services	226	359	784	1,956	180	3,505
	8,846	16,973	40,051	10,517	188	76,575
Transfer of goods/services
Goods/Services transferred in a specific moment	8,506	16,823	39,836	10,517	72	75,754
Goods/Services transferred over a period of time	340	150	215		116	821

(€ million)	2023	2022	2021
Revenues associated with contract liabilities at the beginning of the period	642	157	658
Revenues associated with performance obligations totally or partially satisfied in
previous years	1,087	1	30

Sales from operations by industry segment and geographical area of destination are disclosed in note 35 – Segment information and information by geographical area.

Sales from operations with related parties are disclosed in note 36 – Transactions with related parties.

Other income and revenues

(€ million)	2023	2022	2021
Gains from sale of assets and businesses	27	48	107
Other proceeds	1,072	1,127	1,089
	1,099	1,175	1,196

Other proceeds include €121 million (€204 million and €281 million in 2022 and 2021, respectively) related to the recovery of the cost share of right-of-use assets pertaining to partners of unincorporated joint operations operated by Eni.

Other income and revenues with related parties are disclosed in note 36 – Transactions with related parties.

30 Costs

Purchase, services and other charges

(€ million)	2023	2022	2021
Production costs - raw, ancillary and consumable materials and goods	58,170	85,139	41,174
Production costs - services	11,512	10,303	10,646
Lease expense and other	1,432	2,301	1,233
Net provisions for contingencies	1,369	2,985	707
Other expenses	1,746	2,069	1,983
	74,229	102,797	55,743
less:
- capitalized direct costs associated with self-constructed assets - tangible
assets	(367)	(246)	(185)
- capitalized direct costs associated with self-constructed assets - intangible
assets	(26)	(22)	(9)
	73,836	102,529	55,549

Purchase, services and other charges included prospecting costs, geological and geophysical studies of exploration activities for €205 million (€220 million and € 194 million in 2022 and 2021, respectively).

Costs incurred in connection with research and development activities expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €166 million (€164 million and €177 million in 2022 and 2021, respectively).

Royalties on the extraction rights of hydrocarbons amounted to €1,138 million (€1,570 million and €946 million in 2022 and 2021, respectively).

Additions to provisions net of reversal of unused provisions related to net additions for environmental liabilities amounting to €559 million (net additions of €1,700 million and net reversals of €279 million in 2022 and 2021, respectively) and net reversals for litigations amounting to €87 million (net additions of €501 million and €162 million in 2022 and 2021, 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.

Payroll and related costs

(€ million)	2023	2022	2021
Wages and salaries	2,427	2,311	2,182
Social security contributions	497	465	455
Cost related to employee benefit plans	156	174	165
Other costs	196	194	204
	3,276	3,144	3,006
less:
- capitalized direct costs associated with self-constructed assets - tangible
assets	(131)	(120)	(111)
- capitalized direct costs associated with self-constructed assets - intangible
assets	(9)	(9)	(7)
	3,136	3,015	2,888

Other costs comprised provisions for redundancy incentives of €56 million (€78 million and €94 million in 2022 and 2021, respectively) and costs for defined contribution plans of €102 million (€103 million and €97 million in 2022 and 2021, 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 Group average number and breakdown of employees by category is reported below:

	2023		2022		2021
(number)	Subsidiaries	Joint operations	Subsidiaries	Joint operations	Subsidiaries	Joint operations
Senior managers	944	19	957	19	966	18
Junior managers	9,157	84	9,084	80	9,143	78
Employees	15,810	420	15,517	420	15,747	380
Workers	5,937	294	6,074	288	5,476	284
	31,848	817	31,632	807	31,332	760

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 monetary incentive plan for the managers of Eni

The main characteristic of long term-incentive plans with treasury shares whose assignments are in place at the end of 2023 are described below.

On May 13, 2020 and on May 10, 2023, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2020- 2022 and 2023-2025, respectively, and empowered the Board of Directors to execute the plan by authorizing it to dispose up to a maximum of 20 million of treasury shares in service of the plan 2020-2022 and 16 million in service of the plan 2023-2025 (also authorizing the disposal of treasury shares originally intended for the 2020-2022 Long-Term Incentive Plan, for the part relating to unused shares, equal to approximately 6.7 million shares).

The Long-Term Monetary Incentive plans provide for three annual awards (2020, 2021 and 2022 and 2023, 2024 and 2025, respectively) and are intended for the Chief Executive Officer of Eni and for the managers 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. Considering that these incentives fall within the category of employee compensation, in accordance with IFRS, the cost of the plans is determined based on the fair value of the financial instruments awarded to the beneficiaries and the number of shares that are granted at the end of the vesting period; the cost is accruing along the vesting period.

With reference to the 2020-2022 Plan, the number of shares that will be granted at the end of the vesting period will depend: (i) for 25% on a market relative objective related to the three-year Total Shareholder Return (TSR) measured by the difference, over the three-year period, between the TSR of the Eni stock and the TSR of the FTSE Mib index (the Italian Stock Exchange), adjusted for the Eni's correlation index and compared with the same return recorded by each company of a group of Eni's competitors ("Peer Group" ); (ii) for 20% on an industrial relative objective measured in terms of annual unit value (\$/boe) of the Net Present Value of proved reserves (NPV), compared with the same values recorded by the Peer Group companies, with a final result equal to the average of the annual results over the three-year period; (iii) for 20% on an economic-financial absolute objective measured by the organic Free Cash Flow (FCF) cumulated over the three-year period, compared to the equivalent cumulative value expected in the first three years of the Strategic Plan approved by the Board of Administration in the year of award and assumed unchanged over the performance period. The final calculation of the FCF is carried out net of the effects of exogenous variables, in application of a variance analysis methodology predetermined and approved by the Remuneration Committee, with the aim of enhancing the effective company performance deriving from management action; (iv) for the remaining part (35%) by an objective of environmental sustainability and energy transition divided into three absolute objectives over the three-year period, namely: (a) for 15% from a decarbonisation objective measured by the final value of the intensity of upstream GHG emissions at the end of the three-year period (tCO2eq/kboe), compared to the equivalent value expected in the third year of the Strategic Plan approved by the Board of Directors in the year of attribution assumed unchanged in the performance period; (b) 10% from an energy transition objective measured at the end of the three-year period in terms of Megawatts of installed electricity generation capacity from renewable sources compared to the equivalent value expected in the third year of the Strategic Plan approved by the Board of Directors in the year of attribution assumed unchanged in the performance period; (c) for 10% on a circular economy objective measured in terms of the progress at the end of the three-year period of three relevant projects compared to the progress expected in the third year of the Strategic Plan approved by the Board of Directors in the year of attribution assumed unchanged during the performance period.

With reference to the 2023-2025 Plan, the number of shares that will be granted at the end of the vesting period will depend: (i) for 25% on a market relative objective related to the Total Shareholder Return (TSR) measured by the difference, over the three-year period, between the TSR of the Eni stock and the TSR of the FTSE Mib index (the Italian Stock Exchange), adjuasted for the Eni's correlation index and compared with the same return recorded by each company of the Peer Group; (ii) for 40% on an economic-financial absolute objective measured by the organic Free Cash Flow (FCF) cumulated over the threeyear period, compared to the equivalent cumulative value expected in the first three years of the Strategic Plan approved by the Board of Administration in the year of award and assumed unchanged over the performance period; (iii) for the remaining part (35%) by an objective of environmental sustainability and energy transition divided into three absolute objectives over the three-year period, namely: (a) for 10% from a decarbonisation objective measured by the final value of the intensity of Scope 1 and Scope 2 upstream GHG emissions at the end of the three-year period (tCO2eq/kboe), compared to the equivalent value expected in the third year of the Strategic Plan approved by the Board of Directors in the year of attribution assumed unchanged in the performance period; (b) 15% from an energy transition objective measured at the end of the three-year period in terms of Megawatts of installed electricity generation capacity from renewable sources and biojet fuel production capacity in terms of kton, both compared to the equivalent value expected in the third year of the Strategic Plan approved by the Board of Directors in the year of attribution assumed unchanged in the performance period; (c) for 10% from a circular economy objective measured in terms of percentage value of vertical integration of Agribusiness for the production of biofuels at the end of the three-year period compared to the progress expected in the third year of the Strategic Plan approved by the Board of Directors in the year of attribution assumed unchanged during the performance period.

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. A 50% of the shares that will effectively be granted to each beneficiary in service will be subject to a lock-up clause of one year after the vesting date for the 2020-2022 Long-Term Incentive Plan and two years after the vesting date for the 2023-2025 Long-Term Incentive Plan.

The number of shares awarded at the grant date was: (i) 1,909,849 shares in 2023; with a weighted average fair value of €10.82 per share; (ii) 2,069,685 shares in 2022; with a weighted average fair value of €9.20 per share; (iii) 2,365,581 shares in 2021, with a weighted average fair value of €8.15 per share.

The estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plan (stochastic method for both Long-Term Monetary Incentive plan), taking into account the fair value of the Eni share at the grant date (between €15.482 and €15.068 depending on the grant date for the 2023 award; between €12.918 and €14.324 depending on the grant date for the 2022 award; between €12.164 and €11.642 depending on the grant date for the 2021 award), reduced by dividends expected along the vesting period (between 6.6% and 6.8% for the 2023 award; 6.8% and 6.1% for the 2022; 7.1% and 7.4% for the 2021 award), considering the volatility of the stock (between 28.2% and 28.4% for the 2023 award; between 30% and 31% for the 2022 award; 44% and 45% for the 2021 award), the forecasts relating to the performance parameters, as well as the lower value attributable to the shares considering the lock-up period at the end of the vesting period.

In 2023, the costs related to the long-term monetary incentive plan, recognized as a component of the payroll cost with contra-entry to equity reserves, as they pertain to company employees, amounted to €20 million (€18 million and €16 million in 2022 and 2021, respectively).

Compensation of 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)	2023	2022	2021
Wages and salaries	35	37	29
Post-employment benefits	3	3	3
Other long-term benefits	19	17	15
Indemnities upon termination of employment		9
	57	66	47

Compensation of Directors and Statutory Auditors of Eni SpA

Compensation of Directors amounted to €13.9 million, €11.12 million and €10.13 million in 2023, 2022 and 2021, respectively. Compensation of Statutory Auditors amounted to €0.580 million, €0.589 million and €0.550 million in 2023, 2022 and 2021, respectively.

Compensation included emoluments and social security benefits 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, even if not subject to personal income tax.

Table of Contents

31 Finance income (expense)

(€ million)	2023	2022	2021
Finance income	7,417	8,450	3,723
Finance expense	(8,113)	(9,333)	(4,216)
Net finance income (expense) from financial assets at fair value through profit or
loss	284	(55)	11
Income (expense) from derivative financial instruments	(61)	13	(306)
Finance income (expense)	(473)	(925)	(788)

The analysis of finance income (expense) was as follows:

(€ million)	2023	2022	2021
Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds	(667)	(507)	(475)
Net finance income (expense) on financial assets held for trading	250	(53)	11
Net expenses on other financial assets valued at fair value with effects on profit
and loss	34	(2)
Interest and other expense due to banks and other financial institutions	(207)	(128)	(94)
Interest on lease liabilities	(267)	(315)	(304)
Interest from banks	356	57	4
Interest and other income on financial receivables and securities held for non
operating purposes	14	9	9
	(487)	(939)	(849)
Exchange differences	255	238	476
Income (expense) from derivative financial instruments	(61)	13	(306)
Other finance income (expense)
Interest and other income on financing receivables and securities held for
operating purposes	153	128	67
Capitalized finance expense	94	38	68
Finance expense due to the passage of time (accretion discount) (a)	(341)	(199)	(144)
Other finance income (expense)	(86)	(204)	(100)
	(180)	(237)	(109)
	(473)	(925)	(788)

(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 income (expense) is disclosed in note 24 – Derivative financial instruments and hedge accounting.

Finance income (expense) with related parties are 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)	2023	2022	2021
Dividends	255	351	230
Net gain (loss) on disposals	430	483	1
Other net income (expense)	423	2,789	(8)
	1,108	3,623	223

Dividend income primarily related to Nigeria LNG Ltd for €179 million (€247 million in 2022 and €144 million in 2021) and to Saudi European Petrochemical Co 'IBN ZAHR' for €55 million (€77 million in 2022 and €54 million in 2021).

Gains on disposals for 2023 referred for €420 million to the capital gain realized from the sale to Snam of the 49.9% stake of SeaCorridor Srl including positive exchange differences of €7 million.

Other net income for 2022 referred for €414 million to the capital gain from the fair value measurement of the residual 50.1% stake of SeaCorridor Srl.

Gains on disposals for 2022 referred for €448 million to the capital gains realized following the listing, through an IPO on the Oslo Stock Exchange, of the investee Vår Energi ASA and subsequent sales made on the market.

Other net income for 2022 referred for €2,542 million to the capital gain from the fair value measurement of the business combination between Eni and bp with the establishment of the joint venture Azule Energy Holdings Ltd and includes realized exchange differences on translation of €764 million.

33 Income taxes

(€ million)	2023	2022	2021
Current taxes:
- Italian subsidiaries	97	1,920	439
- subsidiaries of the Exploration & Production segment - outside Italy	5,349	7,027	3,609
- other subsidiaries - outside Italy	185	944	157
	5,631	9,891	4,205
Net deferred taxes:
- Italian subsidiaries	(137)	(2,191)	(45)
- subsidiaries of the Exploration & Production segment - outside Italy	(22)	713	552
- other subsidiaries - outside Italy	(104)	(325)	133
	(263)	(1,803)	640
	5,368	8,088	4,845

Current income taxes payable by Italian subsidiaries include foreign taxes for €242 million.

Income taxes for 2022 included an extraordinary solidarity tax for the year 2022 (€1,036 million) enacted in Italy by Law No. 51/2022, as well as the UK Energy profit levy. Furthermore, the 2022 income taxes included an extraordinary contribution as enacted by Law No. 197/2022 (Italian 2023 Budget Law) calculated on the 2022 taxable income, determined considering the distribution of certain revaluation reserves of the parent company.

The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (same amount in 2022 and 2021) and the effective tax charge is the following:

(€ million)	2023	2022	2021
Profit (loss) before taxation	10,228	22,049	10,685
Tax rate (IRES) (%)	24.0	24.0	24.0
Statutory corporation tax charge (credit) on profit or loss	2,455	5,292	2,564
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy	3,036	3,388	2,301
- extraordinary contribution effect for companies in energy sector		1,971
- impact pursuant to foreign tax effects of italian entities		66	108
- effect of the valuation of the investments under the equity method	(26)	50	180
- effect due to the tax regime provided for intercompany dividends	7	11	54
- Italian regional income tax (IRAP)	91	(18)	140
- tax effects related to previous years	48	(19)	52
- effect of reversals (impairments) of deferred tax assets	(96)	(241)
- impact pursuant to (reversal) impairment of deferred tax assets	(221)	(2,087)	(666)
- other adjustments	74	(325)	112
	2,913	2,796	2,281
Effective tax charge	5,368	8,088	4,845

The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €3,026 million (€2,940 million and €2,040 million in 2022 and 2021, respectively).

Group's effective tax rate amounted to 52.5% and increased compared to the comparative periods due to (36.7% in 2022 and 45.3% in 2021, respectively as consequence of the impact of the UK energy profit levy which is recognized (effective from the third quarter 2022) and of the effect of certain non-deductible tax expenses in the Exploration & Production segment (i.e. exploration write-offs).

34 Earnings (loss) per share

Basic earnings (loss) per ordinary share are calculated by dividing net profit (loss) 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 (loss) per share are calculated by dividing the net profit (loss) 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, 2023, the shares that could be potentially issued related to the estimation of new shares that will vest in connection with the 2020-2022 and 2023-2025 long-term monetary incentive plans and the convertible bond issued in 2023.

In determining basic and diluted earnings (loss) per share, the net profit (loss) 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 (loss) per share was as follows:

		2023	2022	2021
Weighted average number of shares used for basic
earnings (loss) per share		3,303,766,512	3,483,633,816	3,565,973,883
Potential shares to be issued for ILT incentive plan		6,352,583	6,319,989	7,598,593
Potential shares to be issued for Sustainability-linked
bond		17,014,702
Weighted average number of shares used for diluted
earnings (loss) per share		3,327,133,797	3,489,953,805	3,573,572,476
Eni's profit (loss)	(€ million)	4,771	13,887	5,821
Remuneration of subordinated perpetual bonds net
of tax effect	(€ million)	(109)	(109)	(95)
Remuneration of Sustainability-linked bond net of tax
effect	(€ million)	9
Eni's profit (loss) for basic and diluted earnings
(loss) per share	(€ million)	4,671	13,778	5,726
	(€ per
Basic earnings (loss) per share	share)	1.41	3.96	1.61
	(€ per
Diluted earnings (loss) per share	share)	1.40	3.95	1.60

35 Segment information and information by geographic area

Segment information

Eni's segmental reporting reflects the Group's operating segments, whose results are regularly reviewed by the Chief Operating Decision Maker (the CEO) to assess segment performance and to make decisions about resources to be allocated to each segment.

The organization is based on two General Departments:

• Natural Resources, aimed to build up the value of Eni's Oil & Gas upstream portfolio, reducing its carbon footprint by scaling up energy efficiency and expanding production in the natural gas business, and its position in the wholesale market. Furthermore, the Department focuses its actions on the development of carbon capture/ transportation/storage/reuse and CO² compensation projects, as well as the Agri business line focused on developing renewable feedstock supply chains for Eni's biorefining. The Department incorporates the Company's Oil & Gas exploration, development and production activities, natural gas wholesale via pipeline and LNG, the above mentioned CCUS (and transport) projects, CO² offset projects (forests conservation (REDD+)) and agribusiness.
• Energy Evolution, focused on the evolution of the businesses of power generation, transformation and marketing of products from fossil to bio and blue. The responsibility of this Department includes the growth of power generation from renewable energy and biomethane, the coordination of the bio and circular evolution of the Company's traditional and bio refining system and chemical business, and the development of Eni's retail portfolio, providing increasingly more decarbonized products for mobility, household consumption and small enterprises. The Department incorporates the activities of power generation from natural gas and renewables, the Refining and Chemicals businesses, Retail Gas & Power and mobility Marketing. The companies Versalis (chemical products), Enilive (biorefining and sustainable mobility), Eni Plenitude, EniPower and Eni Rewind are consolidated in this Department.

In relation to financial reporting purposes, consistently with the provisions of the applicable accounting principles, management evaluated that the components of the Company whose operating results are regularly reviewed by the CEO to make decisions about the allocation of resources and to assess performances would continue being the single business units which are comprised in the two General Departments, rather than the two groups themselves. Therefore, in order to comply with the provisions of the international reporting standard that regulates the segment reporting (IFRS 8), the reportable segments of Eni as of December 31, 2023, are identified as follows:

• Exploration & Production: research, development and production of crude oil, condensates and natural gas.
• Global Gas & LNG Portfolio (GGP): supply and sale of wholesale natural gas via pipeline, international transport and purchase and marketing of LNG. It includes gas trading activities finalized to hedging and stabilizing the trade margins, as well as optimising the gas asset portfolio.
• Enilive, Refining and Chemicals: supply and processing of crude oil to manufacture refined products (fuels, bitumens, lubricants etcetera) performed by the Refining operating segment. Enilive is the Eni new subsidiary of sustainable mobility and biorefining, which is operational as of January 1, 2023 following the in-kind contibution of certain Group activities, engages in the manufacturing of biofules and the retail marketing of traditional and bio fuels, including the distribution of several energy carriers for mobility, including fossil and biological fuels and electric charging at service stations, as well as the offer of services connected to mobility such as the Enjoy car sharing, catering and in general the services at outlets. It also engages in the wholesale supplies of fuels, bitumen and lubricants. The operating segment Refining and Enilive have been aggregated because the Chief Operating Decision Maker assesses the integrated margins on the refining and sales of fuels. Furthermore, the results of the Chemicals business operating segment were aggregated in this reporting segment because this operating segment presents similar economic returns and similarities in the industrial processes as the refining activity. Finally, this reportable segment also comprises activities of trading oil and products aimed to execute transactions on the market in order to balance supply and stabilize and cover commercial margins.
• Plenitude & Power: retail sales of gas, electricity and related services, production and wholesale sales of electricity from thermoelectric and renewable plants, services for E-mobility (installation of charging stations). It includes trading activities of CO² emission certificates and forward sale of electricity with a view to hedging/optimising the margins of the electricity.
• 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 developed by the subsidiary Eni Rewind. The segment also includes CCUS projects, agribusiness and forestry conservation (REDD+), under development, which were previously reported in the Exploration & Production segment. This resegmentation: (i) reflects the circumstance that the 2023 economics of the businesses involved (CCUS, agri-business and forest conservation) are currently not significant, without, among all, revenues generation; (ii) is functional to allow greater comparability of the E&P segment data with those of peers and take into account the presence of risk factors and returns as well as different production processes between the Exploration & Production activities and those associated with CCUS, Agri and forest conservation. The comparative periods have been restated in line with this reclassification.

Segment information presented to the CEO (the Chief Operating Decision Maker, ex IFRS 8) includes: revenues, operating profit and directly attributable assets and liabilities.

	Exploration	Global Gas & LNG	Enilive, Refining and	Plenitude &	Corporate and Other	Adjustments of intragroup
(€ million)	& Production	Portfolio	Chemicals	Power	activities	profits	Total
2023
Sales from operations including intersegment sales	23,903	20,139	52,558	14,256	1,972
Less: intersegment sales	(13,060)	(3,229)	(393)	(658)	(1,771)
Sales from operations	10,843	16,910	52,165	13,598	201		93,717
Operating profit Net provisions for contingencies	8,549 (347)	2,431 (205)	(1,397) (392)	(464) (74)	(943) (339)	81 (12)	8,257 (1,369)
Depreciation and amortization	(6,148)	(233)	(524)	(466)	(142)	34	(7,479)
Impairments of tangible and intangible assets and right-of-use assets	(1,413)	(3)	(770)	(18)	(58)		(2,262)
Reversals of tangible and intangible assets and right-of-use
assets	376	4	6	48	26		460
Write-off of tangible and intangible assets	(531)			(5)	1		(535)
Share of profit (loss) of equity-accounted investments	1,009	49	343	(55)	(10)		1,336
Identifiable assets (a)	62,180	6,381	15,530	13,999	1,952	(378)	99,664
Unallocated assets (b)							42,942
Equity-accounted investments Identifiable liabilities (a)	6,773	531	3,582	667	1,077		12,630
Unallocated liabilities (b)	18,020	5,997	10,200	6,076	4,629	(56)	44,866
							44,096
Capital expenditure in tangible and intangible assets	7,133	16	982	740	363	(19)	9,215
2022 Sales from operations including intersegment sales	31,194	48,586	59,178	20,883	1,886
Less: intersegment sales	(18,305)	(7,356)	(708)	(1,157)	(1,689)
Sales from operations	12,889	41,230	58,470	19,726	197		132,512
Operating profit	15,963	3,730	460	(825)	(1,956)	138	17,510
Net provisions for contingencies	(147)	(393)	(1,110)	(14)	(1,340)	19	(2,985)
Depreciation and amortization	(6,017)	(217)	(506)	(358)	(140)	33	(7,205)
Impairments of tangible and intangible assets and right-of-use assets	(613)	(6)	(752)	(125)	(71)		(1,567)
Reversals of tangible and intangible assets and right-of-use assets	181	18	35	162	31		427
Write-off of tangible and intangible assets	(596)	(1)	(2)				(599)
Share of profit (loss) of equity-accounted investments	1,526	4	446	(20)	(115)		1,841
Identifiable assets (a)	60,298	12,282	14,925	11,987	1,666	(472)	100,686
Unallocated assets (b)							51,444
Equity-accounted investments	7,314	1	3,084	663	1,030		12,092
Identifiable liabilities (a)	17,339	12,572	9,011	4,787	4,462	(68)	48,103
Unallocated liabilities (b)							48,797
Capital expenditure in tangible and intangible assets	6,252	23	878	631	276	(4)	8,056
2021
Sales from operations including intersegment sales	21,742	20,843	40,374	11,187	1,698
Less: intersegment sales	(12,896)	(3,870)	(323)	(670)	(1,510)
Sales from operations	8,846	16,973	40,051	10,517	188		76,575
Operating profit	10,113	899	45	2,355	(863)	(208)	12,341
Net provisions for contingencies	(221)	(139)	(137)	(1)	(186)	(23)	(707)
Depreciation and amortization Impairments of tangible and intangible assets and right-of-use	(5,976)	(174)	(512)	(286)	(148)	33	(7,063)
assets	(194)	(28)	(1,342)	(132)	(27)		(1,723)
Reversals of tangible and intangible assets	1,438	2		112	4		1,556
Write-off of tangible and intangible assets	(375)		(2)	(1)	(9)		(387)
Share of profit (loss) of equity-accounted investments Identifiable assets (a)	8		(333)		(766)		(1,091)
Unallocated assets (b)	61,699	10,022	13,326	8,343	1,493	(591)	94,292
							43,473
Equity-accounted investments Identifiable liabilities (a)	2,639	17	2,366	667	198		5,887
Unallocated liabilities (b)	17,024	10,072	6,796	3,786	3,360	(49)	40,989 52,257
Capital expenditure in tangible and intangible assets	3,824	19	728	443	224	(4)	5,234

(a) Include assets/liabilities directly associated with the generation of operating profit.

(b) Include assets/liabilities not directly associated with the generation of operating profit.

Information by geographical area

Identifiable assets and investments by geographical area of origin

		Other European	Rest of				Other
(€ million)	Italy	Union	Europe	Americas	Asia	Africa	areas	Total
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
2022
Identifiable assets (a)	29,195	7,689	6,564	8,892	18,653	28,167	1,526	100,686
Capital expenditure in tangible and
intangible assets	1,475	415	205	1,266	1,390	3,163	142	8,056
2021
Identifiable assets (a)	23,718	6,902	6,114	5,718	17,483	33,499	858	94,292
Capital expenditure in tangible and
intangible assets	1,333	199	202	659	1,203	1,604	34	5,234

(a) Include assets directly associated with the generation of operating profit.

Sales from operations by geographical area of destination

(€ million)	2023	2022	2021
Italy	33,450	60,090	29,968
Other European Union	18,271	25,413	14,671
Rest of Europe	18,476	21,748	12,470
Americas	7,004	6,929	4,420
Asia	7,404	9,062	7,891
Africa	9,057	9,191	7,040
Other areas	55	79	115
	93,717	132,512	76,575

36 Transactions with related parties

In the ordinary course of its business, Eni enters into transactions mainly regarding:

• a) purchase/supply of goods and services and the provision of financing to joint ventures, associates and nonconsolidated subsidiaries;
• b) purchase/supply of goods and services to entities controlled by the Italian Government;
• c) purchase/supply of goods and services to companies related to Eni SpA through members of the Board of Directors. Most of these transactions are exempt from the application of the Eni internal procedure "Transactions involving interests of Directors and Statutory Auditors and transactions with related parties" pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or standard conditions, or because they fall below the materiality threshold provided for by the procedure;
• d) contributions to non-profit entities correlated to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation, established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as scientific and technological research; and (ii) Eni Enrico Mattei Foundation, established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge enrichment in the fields of economics, energy and environment, both at the national and international level.

Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and scientific initiatives, are related to the ordinary course of Eni's business.

Transactions and balances with related parties

(€ million)

	December 31, 2023				2023
Name	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
	1,563	4,818	8,041	4,478	15,888	17

(*) Each individual amount included herein was lower than €50 million.

(€ million)

	December 31, 2022				2022
Name	Receivables and other assets	Payables and other liabilities	Guarantees	Revenues	Costs	Other operating (expense) income
Joint ventures and associates
Agiba Petroleum Co	17	71			224
Angola LNG Ltd					79
Coral FLNG SA	10		1,378	12
Azule Group	320	517	3,268	46	1,152
Saipem Group	3	195	9	9	452
Vårgrønn Group			1,259
Karachaganak Petroleum Operating BV	27	251			1,347
Mellitah Oil & Gas BV	58	144		9	234
Petrobel Belayim Petroleum Co	33	595			944
Société Centrale Electrique du Congo SA	47			74
Società Oleodotti Meridionali SpA	6	433		16	14
Vår Energi ASA	58	722	2,378	84	4,085	(597)
Other(*)	127	76	9	167	338
	706	3,004	8,301	417	8,869	(597)
Unconsolidated entities controlled by Eni
Eni BTC Ltd			190
Industria Siciliana Acido Fosforico - ISAF SpA
(in liquidation)	139	4	1	15
Other	8	10	11	7	15
	147	14	202	22	15
	853	3,018	8,503	439	8,884	(597)
Entities controlled by the Government
Cassa Depositi e Prestiti Group	2	47		3	86
Enel Group	438	264		97	275	484
Italgas Group	218	8		84
Snam Group	763	25		1,767	873
Terna Group	119	159		612	701	(18)
GSE - Gestore Servizi Energetici	207	225		7,786	4,039	3,437
ITA Airways - Italia Trasporto Aereo SpA	3			179
Other	12	35		27	33
	1,762	763		10,555	6,007	3,903
Other related parties		2		1	39
Groupement Sonatrach – Eni «GSE»	179	114		33	417
	2,794	3,897	8,503	11,028	15,347	3,306

(*) Each individual amount included herein was lower than €50 million.

(€ million)

	December 31, 2021			2021
Name	Receivables and other assets	Payables and other liabilities	Guarantees	Revenues	Costs	Other operating (expense) income
Joint ventures and associates
Agiba Petroleum Co	13	57			189
Angola LNG Ltd					73
Angola LNG Supply Services Llc			179
Coral FLNG SA	17		1,260	43
Saipem Group	4	134	9	28	174
Karachaganak Petroleum Operating BV	24	213			989
Mellitah Oil & Gas BV	65	290		3	263
Petrobel Belayim Petroleum Co	24	391		2	651
Société Centrale Electrique du Congo SA	50			66
Societa' Oleodotti Meridionali SpA	6	396		18	12
Vår Energi AS	62	526	495	104	2,224	(409)
Other(*)	137	53	2	95	234
	402	2,060	1,945	359	4,809	(409)
Unconsolidated entities controlled by Eni
Eni BTC Ltd			179
Industria Siciliana Acido Fosforico - ISAF SpA
(in liquidation)	124	1	1	13
Other	10	5	10	8	10
	134	6	190	21	10
	536	2,066	2,135	380	4,819	(409)
Entities controlled by the Government
Enel Group	583	461		41	417	373
Italgas Group	1	49		3	560
Snam Group	160	152		159	1,013	1
Terna Group	51	85		203	309	4
GSE - Gestore Servizi Energetici	311	125		2,216	1,238	766
Other(*)	10	33		20	60
	1,116	905		2,642	3,597	1,144
Other related parties		2			33
Groupement Sonatrach – Agip «GSA» and
Organe Conjoint des Opérations «OC SH/FCP»	170	79		30	222
	1,822	3,052	2,135	3,052	8,671	735

(*) 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 from 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. Services charged to Eni's associates are invoiced on the basis of incurred costs;
• the residual debt relating to the payment of the consideration for the assignment of Cardón IV credits;
• supply of upstream specialist services and the share of the guarantee 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 (for more information see note 28 – Guarantees, commitments and risks);
• purchase of crude oil and issue of guarantees against leasing contracts of FPSO vessels from the Azule Group;
• engineering, construction and drilling services by Saipem Group mainly for the Exploration & Production segment;
• acquisition of transport services from SeaCorridor Group;
• a guarantee issued to Vårgrønn Group in relation to the participation in the Dogger Bank offshore wind project;
• the sale of gas to Société Centrale Electrique du Congo SA;
• advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system at the Taranto refinery;
• 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;
• a guarantee issued granted to Eni BTC Ltd for the construction of an oil pipeline; and
• 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 guaranteeing the operation, upgrading and efficiency of the plants for the Ansaldo Group of Cassa Depositi e Prestiti;
• sale of fuel, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group;
• acquisition of natural gas transportation, distribution 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 and purchase and with 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 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 €27 million;
• contributions and service provisions to Eni Enrico Mattei Foundation for €5 million and to Eni Foundation for €4 million.

Financing transactions and balances with related parties

(€ million)

	December 31, 2023			2023
Name	Receivables and cash and cash equivalents	Payables	Guarantees	Finance incomes and derivative financial instruments	Finance Expenses	Other Gain (loss) from Investments
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
	1,862	335	1,449	156	28	445

(*) Each individual amount included herein was lower than €50 million.

(€ million)

	December 31, 2022			2022
Name	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	356				140
Coral South FLNG DMCC			1,499	1	1
Mozambique Rovuma Venture SpA	1,187	57		48	5
Saipem Group		100		16	3
Other(*)	96	28	2	91	10
	1,639	185	1,501	156	159
Unconsolidated entities controlled by Eni
Other	8	31		5	4
	8	31		5	4
Entities controlled by the Government
Enel Group		176
Italgas Group						30
Other	10	40		1	1
	10	216		1	1	30
	1,657	432	1,501	162	164	30

(*) Each individual amount included herein was lower than €50 million.

(€ million)

	December 31, 2021			2021
Name	Receivables and cash and cash equivalents	Payables	Guarantees	Finance incomes	Finance Expenses
Joint ventures and associates
Cardón IV SA	199	2		37
Coral FLNG SA	383			4	1
Coral South FLNG DMCC			1,413	2
Mozambique Rovuma Venture SpA	1,008	72
Other(*)	70	43		35	43
	1,660	117	1,413	78	44
Unconsolidated entities controlled by Eni
Other	38	34		1	1
	38	34		1	1
Entities controlled by the Government
Enel Group		109
Other	2	17			1
	2	126			1
	1,700	277	1,413	79	46

(*) Each individual amount included herein was lower than €50 million.

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 bank debt guarantee issued on behalf of Coral South FLNG DMCC as part of the project financing of the Coral FLNG development project (for more information see note 28 – Guarantees, commitments and risks);
• a loan granted to Mozambique Rovuma Venture SpA for the development of gas reserves offshore Mozambique;
• liabilities for leased assets towards Saipem Group related to long-term contracts for the use of drilling rigs.

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;
• capital gain from the sale to Snam Group of the 49.9% share capital of SeaCorridor Srl.

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:

(€ million)

	December 31, 2023			December 31, 2022
	Related			Related
	Total	parties	Impact %	Total	parties	Impact %
Cash and cash equivalents	10,193	3	0.03	10,155	10	0.10
Other current financial assets	896	19	2.12	1,504	16	1.06
Trade and other receivables	16,551	1,363	8.24	20,840	2,427	11.65
Other current assets	5,637	32	0.57	12,821	341	2.66
Other non-current financial assets	2,301	1,840	79.97	1,967	1,631	82.92
Other non-current assets	3,393	168	4.95	2,236	26	1.16
Short-term debt	4,092	222	5.43	4,446	307	6.91
Current portion of long-term debt	2,921	21	0.72	3,097	36	1.16
Current portion of non-current lease liabilities	1,128	21	1.86	884	35	3.96
Trade and other payables	20,654	4,245	20.55	25,709	3,203	12.46
Other current liabilities	5,579	62	1.11	12,473	232	1.86
Long-term debt	21,716	65	0.30	19,374	26	0.13
Non-current lease liabilities	4,208	6	0.14	4,067	28	0.69
Other non-current liabilities	4,096	511	12.48	3,234	462	14.29

The impact of transactions with related parties on the profit and loss accounts consisted of the following:

(€ million)

	2023			2022			2021
	Total	Related parties	Impact %	Total	Related parties	Impact %	Total	Related parties	Impact %
Sales from operations	93,717	4,322	4.61	132,512	10,872	8.20	76,575	3,000	3.92
Other income and
revenues	1,099	156	14.19	1,175	156	13.28	1,196	52	4.35
Purchases, services
and other	(73,836)	(15,885)	21.51	(102,529)	(15,327)	14.95	(55,549)	(8,644)	15.56
Net (impairments)
reversals of trade and
other receivables	(249)	5		47	(2)		(279)	(6)	2.15
Payroll and related
costs	(3,136)	(8)	0.26	(3,015)	(18)	0.60	(2,888)	(21)	0.73
Other operating
income (expense)	478	17	3.56	(1,736)	3,306		903	735	81.40
Finance income	7,417	155	2.09	8,450	160	1.89	3,723	79	2.12
Finance expense	(8,113)	(28)	0.35	(9,333)	(164)	1.76	(4,216)	(46)	1.09
Derivative financial
instruments	(61)	1		13	2	15.38	(306)
Other income
(expense) from
investments	1,108	445	40.16	3,623	30	0.83	223
				F-141

Main cash flows with related parties are provided below:

(€ million)	2023	2022	2021
Revenues and other income	4,478	11,028	3,052
Costs and other expenses	(13,539)	(13,749)	(7,814)
Other operating income (loss)	17	3,306	735
Net change in trade and other receivables and payables	1,916	(431)	(342)
Net interests	117	69	38
Net cash provided from operating activities	(7,011)	223	(4,331)
Capital expenditure in tangible and intangible assets	(2,349)	(1,596)	(851)
Disposal of investments	440	165
Net change in accounts payable and receivable in relation to investments	504	1,480	(20)
Change in financial receivables	(290)	(81)	(105)
Net cash used in investing activities	(1,695)	(32)	(976)
Change in financial and lease liabilities	(162)	(88)	(13)
Net cash used in financing activities	(162)	(88)	(13)
Change in cash and cash equivalents	(7)	8	2
Total financial flows to related parties	(8,875)	111	(5,318)

The impact of cash flows with related parties consisted of the following:

(€ million)

	2023			2022			2021
	Total	Related parties	Impact %	Total	Related parties	Impact %	Total	Related parties	Impact %
Net cash provided
from operating
activities	15,119	(7,011)		17,460	223	1.28	12,861	(4,331)
Net cash used in
investing activities	(9,365)	(1,695)	18.10	(7,018)	(32)	0.46	(12,022)	(976)	8.12
Net cash used in
financing activities	(5,668)	(162)	2.86	(8,542)	(88)	1.03	(2,039)	(13)	0.64

37 Other information about investments

Information on Eni's investments as of December 31, 2023

The following section provides information about Eni's subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2023. Unless otherwise indicated, share capital is represented by ordinary shares directly held by the Group, while ownership interest corresponds to voting rights.

PARENT COMPANY

Company name		Registered office Country of operation	Currency	Share Capital	Shareholders	% Ownership
Eni SpA (#)	Rome	Italy	EUR		4,005,358,876 Cassa Depositi e Prestiti SpA	27.73
					Ministero dell'Economia e delle Finanze	4.67
					Eni SpA	4.65
					Other shareholders	62.95

SUBSIDIARIES

EXPLORATION & PRODUCTION

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Eni Mediterranea Idrocarburi SpA	Gela (CL)	Italy	EUR	5,200,000 Eni SpA		100.00	100.00	F.C.
Eni Mozambico SpA	San Donato Milanese (MI)	Mozambique	EUR		200,000 Eni SpA	100.00	100.00	F.C.
Eni Natural Energies Mozambico Srl	San Donato Milanese (MI)	Mozambique	EUR		100,000 Eni Natural Energies SpA	100.00		Eq.
Eni Natural Energies SpA	San Donato Milanese (MI)	Italy	EUR		100,000 Eni SpA	100.00	100.00	F.C.
Eni Timor Leste SpA	San Donato Milanese (MI)	East Timor	EUR	4,386,849 Eni SpA		100.00	100.00	F.C.
Eni West Africa SpA	San Donato Milanese (MI)	Angola	EUR	1,000,000 Eni SpA		100.00		Eq.
Floaters SpA	San Donato Milanese (MI)	Italy	EUR	200,120,000 Eni SpA		100.00	100.00	F.C.
Ieoc SpA	San Donato Milanese (MI)	Egypt	EUR	1,518,000 Eni SpA		100.00	100.00	F.C.
Società Petrolifera Italiana SpA	San Donato Milanese (MI)	Italy	EUR	3,652,000 Eni SpA	Third parties	99.96 0.04	99.96	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (#) Company with shares quoted on regulated market of Italy or of other EU countries.

OUTSIDE ITALY

		Country of		Share		%	% Equity	Consolidation or
Company name	Registered office	operation	Currency	Capital	Shareholders	Ownership	ratio	valutation method (*)
Agip Caspian Sea BV	Amsterdam (Netherlands)	Kazakhstan	EUR	20,005	Eni International BV	100.00	100.00	F.C.
Agip Energy and Natural Resources (Nigeria) Ltd	Abuja (Nigeria)	Nigeria	NGN	5,000,000	Eni International BV Eni Oil Holdings BV	95.00 5.00	100.00	F.C.
Agip Karachaganak BV	Amsterdam (Netherlands)	Kazakhstan	EUR	20,005	Eni International BV	100.00	100.00	F.C.
Bacton CCS Ltd	London (United Kingdom)	United Kingdom	GBP	10,000	Eni CCUS H. Ltd	100.00		Eq.
Burren Energy (Bermuda) Ltd	Hamilton (Bermuda)	United Kingdom	USD	12,002	Burren Energy Plc	100.00	100.00	F.C.
Burren Energy (Egypt) Ltd	London (United Kingdom)	Egypt	GBP	2	Burren Energy Plc	100.00		Eq.
Burren Energy Congo Ltd	Road Town (British Virgin Islands)	Republic of the Congo	USD	50,000	Burren En. (Berm) Ltd	100.00	100.00	F.C.
Burren Energy India Ltd	London (United Kingdom)	United Kingdom	GBP	2	Burren Energy Plc	100.00	100.00	F.C.
Burren Energy Plc	London (United Kingdom)	United Kingdom	GBP	28,819,023	Eni UK Holding Plc Eni UK Ltd	99.99 ()	100.00	F.C.
Burren Shakti Ltd	Hamilton (Bermuda)	United Kingdom	USD	213,138	Burren En. India Ltd	100.00	100.00	F.C.
Eni Abu Dhabi BV	Amsterdam (Netherlands)	United Arab Emirates	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Albania BV	Amsterdam (Netherlands)	Albania	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Algeria Exploration BV	Amsterdam (Netherlands)	Algeria	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Algeria Ltd Sàrl	Luxembourg (Luxembourg)	Algeria	USD	20,000	Eni Oil Holdings BV	100.00	100.00	F.C.
Eni Algeria Production BV	Amsterdam (Netherlands)	Algeria	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Ambalat Ltd	London (United Kingdom)	Indonesia	GBP	1	Eni Indonesia Ltd	100.00	100.00	F.C.
Eni America Ltd	Dover (USA)	USA	USD	72,000	Eni UHL Ltd	100.00	100.00	F.C.
Eni Argentina Exploración y Explotación SA	Buenos Aires (Argentina)	Argentina	ARS	31,997,266	Eni International BV Eni Oil	95.00 5.00	100.00	F.C.
					Holdings BV
Eni Arguni I Ltd	London (United Kingdom)	Indonesia	GBP	1	Eni Indonesia Ltd	100.00	100.00	F.C.
Eni Australia BV	Amsterdam (Netherlands)	Australia	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Australia Ltd	London (United Kingdom)	Australia	GBP	20,000,000	Eni International BV	100.00	100.00	F.C.
Eni Bahrain BV	Amsterdam (Netherlands)	Bahrain	EUR	20,000	Eni International BV	100.00	100.00	F.C.

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Eni BB Petroleum Inc	Dover (USA)	USA	USD	1,000	Eni Petroleum Co Inc	100.00	100.00	F.C.
Eni BTC Ltd	London (United Kingdom)	United Kingdom	GBP	1	Eni International BV	100.00		Eq.
Eni Bukat Ltd	London (United Kingdom)	Indonesia	GBP	1	Eni Indonesia Ltd	100.00	100.00	F.C.
Eni Canada Holding Ltd	Calgary (Canada)	Canada	USD	3,938,200,001	Eni International BV	100.00	100.00	F.C.
Eni CBM Ltd	London (United Kingdom)	Indonesia	USD	2,210,728	Eni Lasmo Plc	100.00		Eq.
Eni CCUS Holding Ltd	London (United Kingdom)	United Kingdom	GBP	167,020,000	Eni UK Ltd	100.00	100.00	F.C.
Eni China BV	Amsterdam (Netherlands)	China	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Congo SAU	Pointe-Noire (Republic of the Congo)	Republic of the Congo	USD	500,000	Eni E&P Holding BV	100.00	100.00	F.C.
Eni Côte d'Ivoire Ltd	London (United Kingdom)	Ivory Coast	GBP	1	Eni Lasmo Plc	100.00	100.00	F.C.
Eni Cyprus Ltd	Nicosia (Cyprus)	Cyprus	EUR	2,011	Eni International BV	100.00	100.00	F.C.
Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda	Rio de Janeiro (Brazil)	Brazil	BRL	1,596,052,720	Eni International BV	99.99		Eq.
					Eni Oil Holdings BV	()
Eni East Ganal Ltd	London (United Kingdom)	Indonesia	GBP	1	Eni Indonesia Ltd	100.00	100.00	F.C.
Eni East Med BV	Amsterdam (Netherlands)	Netherlands	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni East Sepinggan Ltd	London (United Kingdom)	Indonesia	GBP	1	Eni Indonesia Ltd Ltd	100.00	100.00	F.C.
Eni Elgin/Franklin Ltd	London (United Kingdom)	United Kingdom	GBP	100	Eni UK Ltd	100.00	100.00	F.C.
Eni Energy Russia BV	Amsterdam (Netherlands)	Netherlands	EUR	20,000	Eni International BV	100.00	100.00	F.C.
Eni Exploration & Production Holding BV	Amsterdam (Netherlands)	Netherlands	EUR	29,832,777.12	Eni International BV	100.00	100.00	F.C.
Eni Ganal Deepwater Ltd	Hamilton (Bermuda)	Indonesia	USD	12,700	Eni Lasmo Plc	100.00	100.00	F.C.
Eni Ganal Ltd	London (United Kingdom)	Indonesia	GBP	2	Eni Indonesia Ltd	100.00	100.00	F.C.
Eni Gas & Power LNG Australia BV	Amsterdam (Netherlands)	Australia	EUR	1,013,439	Eni International BV	100.00	100.00	F.C.
Eni Ghana Exploration and Production Ltd	Accra (Ghana)	Ghana	GHS	21,412,500	Eni International BV	100.00	100.00	F.C.
Eni GoM Llc	Dover (USA)	USA	USD	5,000	Eni Marketing Inc	100.00	100.00	F.C.
Eni Hewett Ltd	Aberdeen (United Kingdom)	United Kingdom	GBP	3,036,000	Eni UK Ltd	100.00	100.00	F.C.
Eni Hydrocarbons Venezuela Ltd	London (United Kingdom)	Venezuela	GBP	8,050,500	Eni Lasmo Plc	100.00		Eq.
Eni In Amenas Ltd	Aberdeen (United Kingdom)	Algeria	USD	1	Eni Algeria Expl.BV	100.00	100.00	F.C.

								Consolidation
		Country of				%	% Equity	or valutation
Company name	Registered office	operation	Currency	Share Capital	Shareholders	Ownership	ratio	method (*)
Eni In Salah Ltd	Nassau (Bahamas)	Algeria	USD		1,002 Eni IS Exploration Ltd	60.48	100.00	F.C.
					Eni Algeria Expl.BV	39.52
Eni India Ltd	London (United Kingdom)	India	GBP		1 Eni Lasmo Plc	100.00		Eq.
Eni Indonesia Ltd	London (United Kingdom)	Indonesia	GBP		100 Eni ULX Ltd	100.00	100.00	F.C.
Eni Indonesia Ots 1 Ltd	George Town (Cayman Islands)	Indonesia	USD	1.01 Eni	Indonesia Ltd	100.00	100.00	F.C.
Eni International NA NV Sàrl	Luxembourg (Luxembourg)	United Kingdom	USD	25,000 Eni	International BV	100.00	100.00	F.C.
Eni Investments Plc	London (United Kingdom)	United Kingdom	GBP	750,050,000 Eni SpA	Eni UK Ltd	99.99 ()	100.00	F.C.
Eni Iran BV	Amsterdam (Netherlands)	Iran	EUR	20,000 Eni	International BV	100.00		Eq.
Eni Iraq BV	Amsterdam (Netherlands)	Iraq	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni IS Exploration Ltd	London (United Kingdom)	United Kingdom	GBP		1 Eni Algeria Expl.BV	100.00	100.00	F.C.
Eni Isatay BV	Amsterdam (Netherlands)	Kazakhstan	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni JPDA 03-13 Ltd	London (United Kingdom)	Australia	GBP	250,000 Eni	International BV	100.00	100.00	F.C.
Eni JPDA 06-105 Pty Ltd	Perth (Australia)	Australia	AUD	80,830,576 Eni	International BV	100.00	100.00	F.C.
Eni JPDA 11-106 BV	Amsterdam (Netherlands)	Australia	EUR	50,000 Eni	International BV	100.00	100.00	F.C.
Eni Kenya BV	Amsterdam (Netherlands)	Kenya	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni Krueng Mane Ltd	London (United Kingdom)	Indonesia	GBP		2 Eni Indonesia Ltd	100.00	100.00	F.C.
Eni Lasmo Plc	London (United Kingdom)	United Kingdom	GBP	337,638,724.25 Eni	Investments Plc Eni UK Ltd	99.99 ()	100.00	F.C.
Eni Lebanon BV	Amsterdam (Netherlands)	Lebanon	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni Liverpool Bay Operating Co Ltd	London (United Kingdom)	United Kingdom	GBP		1 Eni UK Ltd	100.00		Eq.
Eni LNS Ltd	London (United Kingdom)	United Kingdom	GBP		1 Eni UK Ltd	100.00	100.00	F.C.
Eni Makassar Ltd	Hamilton (Bermuda) Indonesia		USD		12,000 Eni Lasmo Plc	100.00	100.00	F.C.
Eni Marketing Inc	Dover (USA)	USA	USD	1,000 Eni	Petroleum Co Inc	100.00	100.00	F.C.
Eni Maroc BV	Amsterdam (Netherlands)	Morocco	EUR	20,000 Eni	International BV	100.00	100.00	F.C.

								Consolidation
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Eni México S. de RL de CV	Mexico City	Mexico	MXN		3,000 Eni International BV	99.90	100.00	F.C.
	(Mexico)				Eni Oil Holdings BV	0.10
Eni Middle East Ltd	London (United	United Arab	GBP		1 Eni ULT Ltd	100.00	100.00	F.C.
	Kingdom)	Emirates
Eni MOG Ltd (in liquidation)	London (United	United	GBP	0	(a) Eni Lasmo Plc	99.99	100.00	F.C.
	Kingdom)	Kingdom			Eni LNS Ltd	()
Eni Montenegro BV	Amsterdam (Netherlands)	Republic of Montenegro	EUR		20,000 Eni International BV	100.00		Eq.
Eni Mozambique Engineering Ltd	London (United	United	GBP		1 Eni Lasmo Plc	100.00		Eq.
	Kingdom)	Kingdom
Eni Mozambique LNG Holding	Amsterdam	Netherlands	EUR		20,000 Eni International BV	100.00	100.00	F.C.
BV	(Netherlands)
Eni Muara Bakau BV	Amsterdam	Indonesia	EUR		20,000 Eni International BV	100.00	100.00	F.C.
	(Netherlands)
Eni Myanmar BV	Amsterdam (Netherlands)	Myanmar	EUR		20,000 Eni International BV	100.00		Eq.
Eni New Energy Egypt SAE	Cairo (Egypt)	Egypt	EGP		250,000 Eni International BV	99.98		Eq.
					Ieoc Exploration BV	0.01
					Ieoc Production BV	0.01
Eni North Africa BV	Amsterdam (Netherlands)	Libya	EUR		20,000 Eni International BV	100.00	100.00	F.C.
Eni North Ganal Ltd	London (United	Indonesia	GBP		1 Eni Indonesia Ltd	100.00	100.00	F.C.
	Kingdom)
Eni Oil & Gas Inc	Dover (USA)	USA	USD		100,800 Eni America Ltd	100.00	100.00	F.C.
Eni Oil Algeria Ltd	London (United	Algeria	GBP		1,000 Eni Lasmo Plc	100.00	100.00	F.C.
	Kingdom)
Eni Oil Holdings BV	Amsterdam (Netherlands)	Netherlands	EUR		450,000 Eni ULX Ltd	100.00	100.00	F.C.
Eni Oman BV	Amsterdam	Oman	EUR		20,000 Eni International BV	100.00	100.00	F.C.
	(Netherlands)
Eni Peri Mahakam Ltd	London (United	Indonesia	GBP		1 Eni Indonesia Ltd	100.00	100.00	F.C.
	Kingdom)
Eni Petroleum Co Inc	Dover (USA)	USA	USD	156,600,000 Eni SpA		63.86	100.00	F.C.
					Eni International BV	36.14
Eni Petroleum US Llc	Dover (USA)	USA	USD		1,000 Eni BB Petroleum Inc	100.00	100.00	F.C.
Eni Qatar BV	Amsterdam	Qatar	EUR		20,000 Eni International BV	100.00	100.00	F.C.
	(Netherlands)
Eni RAK BV	Amsterdam	United Arab	EUR		20,000 Eni International BV	100.00	100.00	F.C.
	(Netherlands)	Emirates
Eni Rapak Deepwater Ltd	Hamilton (Bermuda) Indonesia		USD		12,000 Eni Lasmo Plc	100.00	100.00	F.C.
Eni Rapak Ltd	London (United Kingdom)	Indonesia	GBP		2 Eni Indonesia Ltd	100.00	100.00	F.C.
Eni RD Congo SA	Kinshasa	Democratic	CDF		750,000,000 Eni International BV	99.99		Eq.
	(Democratic Republic of the Congo)	Republic of the Congo			Eni Oil Holdings BV	()

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Shares without nominal value.

		Country of				%	% Equity	Consolidation or valutation
Company name	Registered office	operation	Currency	Share Capital Shareholders		Ownership	ratio	method (*)
Eni Rovuma Basin BV	Amsterdam (Netherlands)	Mozambique	EUR		20,000 Eni Mozamb. LNG H. BV	100.00	100.00	F.C.
Eni Sharjah BV	Amsterdam (Netherlands)	United Arab Emirates	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni South Africa BV	Amsterdam (Netherlands)	Republic of South Africa	EUR	20,000 Eni	International BV	100.00		Eq.
Eni South China Sea Ltd Sàrl	Luxembourg (Luxembourg)	China	USD	20,000 Eni	International BV	100.00		Eq.
Eni Timor 22-23 BV	Amsterdam (Netherlands)	East Timor	EUR	20,000 Eni	International BV	100.00		Eq.
Eni TNS Ltd	Aberdeen (United Kingdom)	United Kingdom	GBP		1,000 Eni UK Ltd	100.00	100.00	F.C.
Eni Tunisia BV	Amsterdam (Netherlands)	Tunisia	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni Turkmenistan Ltd	Hamilton (Bermuda)	Turkmenistan	USD		20,000 Burren En. (Berm) Ltd	100.00	100.00	F.C.
Eni UHL Ltd	London (United Kingdom)	United Kingdom	GBP		1 Eni ULT Ltd	100.00	100.00	F.C.
Eni UK Holding Plc	London (United Kingdom)	United Kingdom	GBP	424,050,000 Eni Lasmo	Plc Eni UK Ltd	99.99 ()	100.00	F.C.
Eni UK Ltd	London (United Kingdom)	United Kingdom	GBP	50,000,000 Eni	International BV	100.00	100.00	F.C.
Eni UKCS Ltd	London (United Kingdom)	United Kingdom	GBP		100 Eni UK Ltd	100.00	100.00	F.C.
Eni Ukraine Holdings BV	Amsterdam (Netherlands)	Netherlands	EUR	20,000 Eni	International BV	100.00		Eq.
Eni Ukraine LLC (in liquidation)	Kiev (Ukraine)	Ukraine	UAH	98,419,627.51 Eni Ukraine	Hold. BV Eni International BV	99.99 0.01
Eni ULT Ltd	London (United Kingdom)	United Kingdom	GBP	93,215,492.25 Eni Lasmo	Plc	100.00	100.00	F.C.
Eni ULX Ltd	London (United Kingdom)	United Kingdom	GBP		200,010,000 Eni ULT Ltd	100.00	100.00	F.C.
Eni US Operating Co Inc	Dover (USA)	USA	USD	1,000 Eni	Petroleum Co Inc	100.00	100.00	F.C.
Eni USA Gas Marketing Llc	Dover (USA)	USA	USD	10,000 Eni	Marketing Inc	100.00	100.00	F.C.
Eni USA Inc	Dover (USA)	USA	USD		1,000 Eni Oil & Gas Inc	100.00	100.00	F.C.
Eni Venezuela BV	Amsterdam (Netherlands)	Venezuela	EUR	20,000 Eni	Venezuela E&P H.	100.00	100.00	F.C.
Eni Venezuela E&P Holding SA	Bruxelles (Belgium)	Belgium	USD	254,443,200 Eni	International BV Eni Oil Holdings BV	99.99 ()	100.00	F.C.
Eni Vietnam BV	Amsterdam (Netherlands)	Vietnam	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Eni West Ganal Ltd	London (United Kingdom)	Indonesia	GBP		1 Eni Indonesia Ltd	100.00	100.00	F.C.
Eni West Timor Ltd	London (United Kingdom)	Indonesia	GBP		1 Eni Indonesia Ltd	100.00	100.00	F.C.

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Eni Yemen Ltd	London (United Kingdom)	United Kingdom	GBP		1,000 Burren Energy Plc	100.00		Eq.
Export LNG Ltd	Hong Kong (Hong Kong)	Republic of the Congo	USD	322,325,000 Eni SpA		100.00	100.00	F.C.
First Calgary Petroleums LP	Wilmington (USA)	Algeria	USD		1 Eni Canada Hold. Ltd FCP Partner Co ULC	99.99 0.01	100.00	F.C.
First Calgary Petroleums Partner Co ULC	Calgary (Canada)	Canada	CAD		10 Eni Canada Hold. Ltd	100.00	100.00	F.C.
Ieoc Exploration BV	Amsterdam (Netherlands)	Egypt	EUR	20,000 Eni	International BV	100.00		Eq.
Ieoc Production BV	Amsterdam (Netherlands)	Egypt	EUR	20,000 Eni	International BV	100.00	100.00	F.C.
Lasmo Sanga Sanga Ltd	Hamilton (Bermuda)	Indonesia	USD		12,000 Eni Lasmo Plc	100.00	100.00	F.C.
Liverpool Bay CCS Ltd	London (United Kingdom)	United Kingdom	GBP		117,310,000 Eni CCUS H. Ltd	100.00	100.00	F.C.
Liverpool Bay Ltd (in liquidation)	London (United Kingdom)	United Kingdom	USD		1 Eni ULX Ltd	100.00		Co.
LLC "Eni Energhia"	Moscow (Russia)	Russia	RUB		2,000,000 Eni Energy Russia BV Eni Oil Holdings BV	99.90 0.10		Eq.
Mizamtec Operating Company S. de RL de CV	Mexico City (Mexico)	Mexico	MXN		3,000 Eni US Op. Co Inc Eni Petroleum Co Inc	99.90 0.10		Eq.
Nigerian Agip CPFA Ltd	Lagos (Nigeria)	Nigeria	NGN		1,262,500 NAOC Ltd Agip En Nat Res. Ltd Nigerian Agip E. Ltd	98.02 0.99 0.99		Co.
Nigerian Agip Exploration Ltd	Abuja (Nigeria)	Nigeria	NGN	5,000,000 Eni	International BV Eni Oil Holdings BV	99.99 0.01	100.00	F.C.
Nigerian Agip Oil Co Ltd	Abuja (Nigeria)	Nigeria	NGN	1,800,000 Eni	International BV Eni Oil Holdings BV	99.89 0.11	100.00	F.C.
Zetah Congo Ltd	Nassau (Bahamas)	Republic of the Congo	USD		300 Eni Congo SAU Burren En. Congo Ltd	66.67 33.33		Co.
Zetah Kouilou Ltd	Nassau (Bahamas)	Republic of the Congo	USD		2,000 Eni Congo SAU Burren En. Congo Ltd	54.50 37.00		Co.
					Third parties	8.50

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

Table of Contents GLOBAL GAS & LNG PORTFOLIO

IN ITALY

								Consolidation or
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	valutation method (*)
Eni Gas Transport Services Srl	San Donato Milanese (MI)	Italy	EUR		120,000 Eni SpA	100.00		Co.
Eni Global Energy Markets SpA	Rome	Italy	EUR	41,233,720 Eni SpA		100.00	100.00	F.C.
LNG Shipping SpA	San Donato Milanese (MI)	Italy	EUR	240,900,000 Eni SpA		100.00	100.00	F.C.

OUTSIDE ITALY

Table of Contents

								Consolidation or
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	valutation method (*)
Eni España Comercializadora de Gas SAU	Madrid (Spain)	Spain	EUR	2,340,240 Eni SpA		100.00	100.00	F.C.
Eni G&P Trading BV	Amsterdam (Netherlands)	Turkey	EUR	70,000 Eni	International BV	100.00	100.00	F.C.
Eni Gas Liquefaction BV	Amsterdam (Netherlands)	Netherlands	EUR	20,000 Eni	International BV	100.00	100.00	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

ENILIVE, REFINING AND CHEMICALS

Enilive and Refining

IN ITALY

								Consolidation
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Ecofuel SpA	San Donato Milanese (MI)	Italy	EUR	52,000,000 Eni SpA		100.00	100.00	F.C.
EniBioCh4 in Alexandria Srl Società Agricola	San Donato Milanese (MI)	Italy	EUR		50,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4in Aprilia Srl	San Donato Milanese (MI)	Italy	EUR		10,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Flaibano Srl Società Agricola	San Donato Milanese (MI)	Italy	EUR		50,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Grupellum Società Agricola Srl	San Donato Milanese (MI)	Italy	EUR		100,000 EniBioCh4in SpA Third parties	98.00 2.00	98.00	F.C.
EniBioCh4 in Jonica Srl	San Donato Milanese (MI)	Italy	EUR		20,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Momo Società Agricola Srl	San Donato Milanese (MI)	Italy	EUR		20,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Pannellia BioGas Srl Società Agricola	San Donato Milanese (MI)	Italy	EUR		50,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Po Energia Srl Società Agricola (former Po' Energia Srl Società Agricola)	San Donato Milanese (MI)	Italy	EUR		10,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Quadruvium Srl Società Agricola	San Donato Milanese (MI)	Italy	EUR		100,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in Service BioGas Srl	San Donato Milanese (MI)	Italy	EUR		50,000 EniBioCh4in SpA	100.00	100.00	F.C.
EniBioCh4 in SpA	San Donato Milanese (MI)	Italy	EUR	2,500,000 Eni Sust.	Mobility SpA	100.00	100.00	F.C.
Enimoov SpA (former Eni Fuel SpA)	Rome	Italy	EUR	59,944,310 Eni Sust.	Mobility SpA	100.00	100.00	F.C.
Eni Sustainable Mobility SpA	Rome	Italy	EUR	311,509,143 Eni SpA		100.00	100.00	F.C.
Eni Trade & Biofuels SpA	Rome	Italy	EUR	22,568,759 Eni SpA		100.00	100.00	F.C.
Petroven Srl	Genova	Italy	EUR		918,520 Ecofuel SpA	100.00	100.00	F.C.
Raffineria di Gela SpA	Gela (CL)	Italy	EUR	15,000,000 Eni Sust.	Mobility SpA	100.00	100.00	F.C.
SeaPad SpA	Genova	Italy	EUR		12,400,000 Ecofuel SpA Third parties	80.00 20.00		Eq.

OUTSIDE ITALY

								Consolidation
		Country of				%	% Equity	or valutation
Company name	Registered office	operation	Currency	Share Capital	Shareholders	Ownership	ratio	method (*)
Eni Abu Dhabi Refining & Trading BV Amsterdam	(Netherlands)	Netherlands	EUR		20,000 Eni International BV	100.00	100.00	F.C.
Eni Abu Dhabi Refining & Trading	Amsterdam	United Arab	EUR		20,000 Eni Abu Dhabi	100.00		Eq.
Services BV	(Netherlands)	Emirates			R&T BV
Eni Austria GmbH	Wien (Austria)	Austria	EUR		78,500,000 Eni Sust. Mobility	75.00	100.00	F.C.
					SpA
					Eni Deutsch.	25.00
					GmbH
Eni Benelux BV	Rotterdam (Netherlands)	Netherlands	EUR		1,934,040 Eni Sust. Mobility SpA	100.00	100.00	F.C.
Eni Deutschland GmbH	Munich (Germany)	Germany	EUR		90,000,000 Eni Sust. Mobility	89.00	100.00	F.C.
					SpA
					Eni International	11.00
					BV
Eni Ecuador SA	Quito (Ecuador)	Ecuador	USD		103,142.08 Eni International	99.93	100.00	F.C.
					BV
					Esain SA	0.07
Eni Energy (Shanghai) Co Ltd	Shanghai (China)	China	EUR		5,000,000 Eni Sust. Mobility	100.00	100.00	F.C.
					SpA
Eni France Sàrl	Lyon (France)	France	EUR		56,800,000 Eni Sust. Mobility	100.00	100.00	F.C.
					SpA
Eni Iberia SLU	Alcobendas (Spain)	Spain	EUR		17,299,100 Eni Sust. Mobility	100.00	100.00	F.C.
					SpA
Eni Marketing Austria GmbH	Wien (Austria)	Austria	EUR		19,621,665.23 Eni Mineralölh.	99.99	100.00	F.C.
					GmbH
					Eni Sust. Mobility SpA	()
Eni Mineralölhandel GmbH	Wien (Austria)	Austria	EUR		34,156,232.06 Eni Austria GmbH	100.00	100.00	F.C.
Eni Schmiertechnik GmbH	Wurzburg (Germany)	Germany	EUR		2,000,000 Eni Deutsch. GmbH	100.00	100.00	F.C.
Eni Suisse SA	Lausanne	Switzerland	CHF		102,500,000 Eni Sust. Mobility	100.00	100.00	F.C.
	(Switzerland)				SpA
Eni Sustainable Mobility US Inc	Dover (USA)	USA	USD		1,000 Eni Sust. Mobility	100.00	100.00	F.C.
					SpA
Eni Trading & Shipping Inc	Dover (USA)	USA	USD		1,000,000 ET&B SpA	100.00	100.00	F.C.
Eni Transporte y Suministro México S.	Mexico City	Mexico	MXN		3,000 Eni International	99.90	100.00	F.C.
de RL de CV	(Mexico)				BV
					Eni Oil Holdings	0.10
					BV
Eni USA R&M Co Inc	Wilmington (USA)	USA	USD		11,000,000 Eni International	100.00		Eq.
					BV
Esacontrol SA	Quito (Ecuador)	Ecuador	USD		60,000 Eni Ecuador SA	87.00		Eq.
					Third parties	13.00
Esain SA	Quito (Ecuador)	Ecuador	USD		30,000 Eni Ecuador SA	99.99	100.00	F.C.
Oléoduc du Rhône SA	Bovernier	Switzerland	CHF		Tecnoesa SA 7,000,000 Eni International	() 100.00		Eq.
	(Switzerland)				BV
Tecnoesa SA	Quito (Ecuador)	Ecuador	USD		36,000 Eni Ecuador SA	99.99		Eq.
					Esain SA	()

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

Chemicals

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Versalis SpA	San Donato Milanese (MI)	Italy	EUR	300,000,000 Eni SpA		100.00	100.00	F.C.
Finproject SpA	Morrovalle (MC)	Italy	EUR		18,500,000 Versalis SpA	100.00	100.00	F.C.
Mater-Agro Srl	Novara	Italy	EUR		50,000 Novamont SpA Third parties	85.00 15.00		Eq.
Mater-Biotech SpA	Novara	Italy	EUR		120,000 Novamont SpA	100.00	100.00	F.C.
Matrìca SpA	Porto Torres (SS)	Italy	EUR	37,500,000 Novamont	SpA Versalis SpA	50.00 50.00	100.00	F.C.
Novamont SpA	Novara	Italy	EUR		20,000,000 Versalis SpA	100.00	100.00	F.C.

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency		Share Capital Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Asian Compounds Ltd	Hong Kong (Hong Kong)	Hong Kong	HKD		1,000 Finproject Asia Ltd	100.00	100.00	F.C.
BBI Sverige AB	Torsby (Sweden)	Sweden	SEK		100,000 BioBag International	100.00		Eq.
BioBag Americas Inc	Dunedin (USA)	USA	USD		476 BioBag International	100.00	100.00	F.C.
BioBag Finland OY	Vantaa (Finland)	Finland	EUR		203,784 BioBag International Third parties	97.99 2.01		Eq.
BioBag Inc	Toronto (Canada)	Canada	CAD		100 BioBag International	100.00		Eq.
BioBag International AS	Indre Østfold (Norway)	Norway	NOK		3,565,000 Novamont SpA	100.00	100.00	F.C.
BioBag Norge AS	Indre Østfold (Norway)	Norway	NOK		200,000 BioBag International	100.00		Eq.
BioBag Plastics Ltd	Delgany (Ireland)	Ireland	EUR		1,000 BioBag International Third parties	90.10 9.90		Eq.
BioBag Polska Sp zoo	Wroclaw (Poland)	Poland	PLN		106,100 BioBag International	100.00		Eq.
BioBag UK Ltd	Belfast (United Kingdom)	United Kingdom	GBP		1,000 BioBag International Third parties	90.10 9.90		Eq.
BioBag Zenzo A/S	Hillerød (Denmark)	Denmark	DKK		400,000 BioBag International	100.00		Eq.
Dagöplast AS	Hiiumaa (Estonia)	Estonia	EUR		76,800 BioBag International	100.00	100.00	F.C.
Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság	Budapest (Hungary)	Hungary	HUF	5,219,443,200 Versalis SpA	Versalis Deutsch. GmbH Versalis	96.34 1.83 1.83	100.00	F.C.
Finproject Asia Ltd	Hong Kong (Hong	Hong Kong	USD		International SA 1,000 Finproject	100.00	100.00	F.C.
	Kong)				SpA

Table of Contents

								Consolidation
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Finproject Brasil Industria De Solados Eireli	Franca (Brazil)	Brazil	BRL		1,000,000 Finproject SpA	100.00		Eq.
Finproject Guangzhou Trading Co Ltd	Guangzhou (China)	China	USD		180,000 Finproject SpA	100.00	100.00	F.C.
Finproject India Pvt Ltd	Jaipur (India)	India	INR		46,712,940 Versalis Singapore P. Ltd	99.99	100.00	F.C.
					Finproject SpA	()
Finproject Romania Srl	Valea Lui Mihai (Romania)	Romania	RON		7,523,030 Finproject SpA	100.00	100.00	F.C.
Finproject Viet Nam Company Limited	Hai Phong (Vietnam)	Vietnam	VND		19,623,250,000 Finproject Asia Ltd	100.00		Eq.
Foam Creations (2008) Inc	Quebec City (Canada)	Canada	CAD		1,215,000 Finproject SpA	100.00	100.00	F.C.
Foam Creations México SA de CV	León (Mexico)	Mexico	MXN		35,956,433 Foam Creations (2008) Finproject SpA	53.23 46.77	100.00	F.C.
Novamont France SAS	Paris (France)	France	EUR		40,000 Novamont SpA	100.00	100.00	F.C.
Novamont GmbH	Eschborn (Germany)	Germany	EUR		25,564 Novamont SpA	100.00		Eq.
Novamont Iberia SLU	Cornellà de Llobregat (Spain)	Spain	EUR		50,000 Novamont SpA	100.00	100.00	F.C.
Novamont North America Inc	Shelton (USA)	USA	USD		50,000 Novamont SpA	100.00	100.00	F.C.
Padanaplast America Llc	Wilmington (USA)	USA	USD		70,000 Finproject SpA	100.00		Eq.
Padanaplast Deutschland GmbH	Hannover (Germany)	Germany	EUR		25,000 Finproject SpA	100.00		Eq.
Versalis Americas Inc	Dover (USA)	USA	USD		100,000 Versalis International SA	100.00	100.00	F.C.
Versalis Congo Sarlu	Pointe-Noire (Republic of the Congo)	Republic of the Congo	XAF	1,000,000 Versalis	International SA	100.00	100.00	F.C.
Versalis Deutschland GmbH	Eschborn (Germany)	Germany	EUR		100,000 Versalis SpA	100.00	100.00	F.C.
Versalis France SAS	Mardyck (France)	France	EUR	126,115,582.90 Versalis SpA		100.00	100.00	F.C.
Versalis International Côte d'Ivoire Sarlu	Abidjan (Ivory Coast)	Ivory Coast	XOF	270,000,000 Versalis	International SA	100.00		Eq.
Versalis International SA	Bruxelles (Belgium)	Belgium	EUR	15,449,173.88 Versalis SpA	Versalis Deutsch. GmbH	59.00 23.71	100.00	F.C.
					Dunastyr Zrt	14.43
					Versalis France	2.86
Versalis Kimya Ticaret Limited Sirketi	Istanbul (Turkey)	Turkey	TRY		20,000 Versalis International SA	100.00	100.00	F.C.
Versalis México S. de RL de CV	Mexico City (Mexico)	Mexico	MXN	45,001,000 Versalis	International SA	99.99	100.00	F.C.
					Versalis SpA	()
Versalis Pacific (India) Private Ltd	Mumbai (India)	India	INR		238,700 Versalis Singapore P. Ltd	99.99	100.00	F.C.
					Versalis International SA	()
Versalis Pacific Trading (Shanghai) Co Ltd	Shanghai (China)	China	CNY		15,237,236 Versalis SpA	100.00	100.00	F.C.
Versalis Singapore Pte Ltd	Singapore (Singapore)	Singapore	SGD		5,886,800 Versalis SpA	100.00	100.00	F.C.
Versalis UK Ltd	London (United Kingdom)	United Kingdom	GBP		4,018,042 Versalis SpA	100.00	100.00	F.C.
Versalis Zeal Ltd	Takoradi (Ghana)	Ghana	GHS	5,650,000 Versalis	International SA	80.00	80.00	F.C.
					Third parties	20.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

PLENITUDE & POWER

Plenitude

IN ITALY

								Consolidation or
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	valutation method (*)
Eni Plenitude SpA Società Benefit	San Donato Milanese (MI)	Italy	EUR	770,000,000 Eni SpA		100.00	100.00	F.C.
Agrikroton Srl - Società Agricola	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar Srl	100.00	100.00	F.C.
Be Charge Srl	Milan	Italy	EUR		500,000 Be Power SpA	100.00	100.00	F.C.
Be Charge Valle d'Aosta Srl	Milan	Italy	EUR		10,000 Be Charge Srl	100.00	100.00	F.C.
Be Power SpA	Milan	Italy	EUR	698,251 Eni	Plenitude SpA SB	99.19(a)	100.00	F.C.
Borgia Wind Srl	Cesena (FC)	Italy	EUR		Third parties 100,000 Eni Plen. Wind 2020 Srl	0.81 100.00	100.00	F.C.
Corridonia Energia Srl	Cesena (FC)	Italy	EUR		20,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Dynamica Srl	Cesena (FC)	Italy	EUR		50,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
Ecoener Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Elettro Sannio Wind 2 Srl	Cesena (FC)	Italy	EUR		1,225,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
Enerkall Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Eni New Energy SpA	San Donato Milanese (MI)	Italy	EUR	9,296,000 Eni	Plenitude SpA SB	100.00	100.00	F.C.
Eni Plenitude Miniwind Srl (former SEF Miniwind Srl)	Cesena (FC)	Italy	EUR		50,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Eni Plenitude Società Agricola Bio Srl (former Società Agricola SEF Bio Srl)	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Eni Plenitude Solar & Miniwind Italia Srl (former SEF Srl)	Cesena (FC)	Italy	EUR		25,000 Eni New Energy SpA	100.00	100.00	F.C.
Eni Plenitude Solar Abruzzo Srl (former SEF Solar Abruzzo Srl)	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Eni Plenitude Solar III Srl (former SEF Green Srl)	Cesena (FC)	Italy	EUR		500 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Eni Plenitude Solar II Srl (former SEF Solar II Srl)	Cesena (FC)	Italy	EUR		1,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Eni Plenitude Solar Srl (former SEF Solar Srl)	Cesena (FC)	Italy	EUR		120,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Controlling interest: Eni Plenitude SpA SB 100.00

Table of Contents

Consolidation

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Eni Plenitude Technical Services Srl (former PLT Engineering Srl)	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Eni Plenitude Wind & Energy Srl (former PLT Energia Srl)	Cesena (FC)	Italy	EUR		3,865,474 Eni New Energy SpA	100.00	100.00	F.C.
Eni Plenitude Wind 2020 Srl (former PLT Wind 2020 Srl)	Cesena (FC)	Italy	EUR		1,000,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Eni Plenitude Wind 2022 SpA (former PLT Wind 2022 SpA)	Cesena (FC)	Italy	EUR		1,000,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Eolica Pietramontecorvino Srl	Cesena (FC)	Italy	EUR		100,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Eolica Wind Power Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
Eolo Energie - Corleone - Campofiorito Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.
Evolvere SpA Società Benefit	Milan	Italy	EUR	1,130,000 Eni	Plenitude SpA SB	100.00	100.00	F.C.
Evolvere Venture SpA	Milan	Italy	EUR		50,000 Evolvere SpA Soc. Ben.	100.00	100.00	F.C.
Faren Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar III Srl	100.00	100.00	F.C.
FAS Srl	Cesena (FC)	Italy	EUR		119,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Fotovoltaica Pietramontecorvino Srl	Cesena (FC)	Italy	EUR		100,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
FV4P Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Gemsa Solar Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
GPC Due Srl	Cesena (FC)	Italy	EUR		12,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
GPC Uno Srl	Cesena (FC)	Italy	EUR		25,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Green Parity Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Lugo Società Agricola Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar Srl	100.00	100.00	F.C.
Lugo Solar Tech Srl	Cesena (FC)	Italy	EUR		100,000 Eni Plen. Solar Srl	100.00	100.00	F.C.
Marano Solar Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar Srl	100.00	100.00	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

Table of Contents

								Consolidation
								or
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	valutation method (*)
Marano Solare Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Marcellinara Wind Srl	Cesena (FC)	Italy	EUR		35,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
Micropower Srl	Cesena (FC)	Italy	EUR		30,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.
Molinetto Srl	Cesena (FC)	Italy	EUR		10,000 Faren Srl	100.00	100.00	F.C.
Montefano Energia Srl	Cesena (FC)	Italy	EUR		20,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Monte San Giusto Solar Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Olivadi Srl	Cesena (FC)	Italy	EUR		100,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.
Parco Eolico di Tursi e Colobraro Srl	Cesena (FC)	Italy	EUR		31,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
Pescina Wind Srl	Cesena (FC)	Italy	EUR		50,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.
Pieve5 Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar Srl	100.00	100.00	F.C.
Pollenza Sole Srl	Cesena (FC)	Italy	EUR		32,500 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Ravenna 1 FTV Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
RF-AVIO Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
RF-Cavallerizza Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Ruggiero Wind Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
SAV - Santa Maria Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
Società Agricola Agricentro Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar Srl	100.00	100.00	F.C.
Società Agricola Casemurate Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
Società Agricola Forestale Pianura Verde Srl	Cesena (FC)	Italy	EUR		100,000 Soc. Agr. Agricentro Srl	100.00	100.00	F.C.
Società Agricola Isola d'Agri Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Solar Srl	100.00	100.00	F.C.

Table of Contents

		Country of		Share		%	% Equity	Consolidation or valutation method
Company name	Registered office	operation	Currency	Capital	Shareholders	Ownership	ratio	(*)
Società Agricola L'Albero Azzurro Srl	Cesena (FC)	Italy	EUR		100,000 Soc. Agr. Agricentro Srl	100.00	100.00	F.C.
Timpe Muzzunetti 2 Srl	Cesena (FC)	Italy	EUR		2,500 Eni Plen. Wind & En. Srl	70.00	70.00	F.C.
					Third parties	30.00
Vivaro FTV Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl	100.00	100.00	F.C.
VRG Wind 127 Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
VRG Wind 149 Srl	Cesena (FC)	Italy	EUR		10,000 Eni Plen. Wind 2022 SpA	100.00	100.00	F.C.
W-Energy Srl	Cesena (FC)	Italy	EUR		93,000 Eni Plen. Wind & En. Srl	100.00	100.00	F.C.
Wind Salandra Srl	Cesena (FC)	Italy	EUR		100,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.
Windsol Srl	Cesena (FC)	Italy	EUR		3,250,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.
Wind Turbines Engineering 2 Srl	Cesena (FC)	Italy	EUR		5,450,000 Eni Plen. Wind 2020 Srl	100.00	100.00	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

OUTSIDE ITALY

Table of Contents

								Consolidation or
Company name	Registered office	Country of operation	Currency	Share Capital Shareholders		% Ownership	% Equity ratio	valutation method (*)
Adriaplin Podjetje za distribucijo	Ljubljana	Slovenia	EUR	12,956,935 Eni		51.00	51.00	F.C.
zemeljskega plina doo Ljubljana	(Slovenia)				Plenitude
					SpA SB	49.00
Aleria Solar SAS	Bastia (France)	France	EUR		Third parties 100 Eni Plen. Op.	100.00	100.00	F.C.
					Fr. SAS
Almazara Solar SLU	Madrid (Spain)	Spain	EUR	3,000 Eni		100.00	100.00	F.C.
					Plenitude SpA SB
Alpinia Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen.	100.00	100.00	F.C.
					Ren. Lux. Sàrl
Anberia Invest SLU	Madrid (Spain)	Spain	EUR		13,000 Eni Plen. T. S.	100.00	100.00	F.C.
Argon SAS	Argenteuil (France) France		EUR		Spain 180,000 Eni Plen. Op.	100.00	100.00	F.C.
					Fr. SAS
Armadura Solar SLU	Madrid (Spain)	Spain	EUR	3,000 Eni		100.00	100.00	F.C.
					Plenitude
Arm Wind Llp	Astana	Kazakhstan	KZT	19,069,100,000 Eni Energy	SpA SB	100.00	100.00	F.C.
	(Kazakhstan)				Solutions BV
Athies-Samoussy Solar PV1 SAS	Argenteuil (France) France		EUR		68,000 Krypton SAS	100.00	100.00	F.C.
Athies-Samoussy Solar PV2 SAS	Argenteuil (France) France		EUR		40,000 Krypton SAS	100.00	100.00	F.C.
Athies-Samoussy Solar PV3 SAS	Argenteuil (France) France		EUR		36,000 Krypton SAS	100.00	100.00	F.C.
Athies-Samoussy Solar PV4 SAS	Argenteuil (France) France		EUR		14,000 Xenon SAS	100.00	100.00	F.C.
Athies-Samoussy Solar PV5 SAS	Argenteuil (France) France		EUR		14,000 Xenon SAS	100.00	100.00	F.C.
Atlante Solar SLU	Madrid (Spain)	Spain	EUR	3,000 Eni		100.00	100.00	F.C.
					Plenitude
					SpA SB
Belle Magiocche Solaire SAS	Bastia (France)	France	EUR		10,000 Eni Plen. Op. Fr. SAS	100.00	100.00	F.C.
Boceto Solar SLU	Madrid (Spain)	Spain	EUR	3,000 Eni		100.00	100.00	F.C.
					Plenitude
					SpA SB
Bonete Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Brazoria Class B Member Llc	Dover (USA)	USA	USD		1,000 Eni New	100.00	100.00	F.C.
					Energy US
					Inc
Brazoria County Solar Project Llc	Dover (USA)	USA	USD		1,000 Brazoria HoldCo Llc	100.00	90.69	F.C.
Brazoria HoldCo Llc	Dover (USA)	USA	USD	194,670,209 Brazoria		90.69	90.69	F.C.
					Class B
					Third parties	9.31
BT Kellam Solar Llc	Austin (USA)	USA	USD		1,000 Kellam Tax Eq. Partn.	100.00	95.25	F.C.
Camelia Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen.	100.00	100.00	F.C.
					Ren. Lux. Sàrl
Celtis Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen.	100.00	100.00	F.C.
Chapitel Solar SLU	Madrid (Spain)	Spain	EUR	3,000 Eni	Ren. Lux. Sàrl	100.00	100.00	F.C.
					Plenitude
					SpA SB
Corazon Energy Class B Llc	Dover (USA)	USA	USD		100 Eni New	100.00	100.00	F.C.
					Energy US Inc
Corazon Energy Llc	Dover (USA)	USA	USD		100 Corazon Tax	100.00	94.03	F.C.
					Eq. Part. Llc

Table of Contents

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Corazon Energy Services Llc	Dover (USA)	USA	USD		100 Eni New Energy US Inc	100.00		Eq.
Corazon Tax Equity Partnership Llc	Dover (USA)	USA	USD		184,488,333 Corazon En. Class B Llc	94.03	94.03	F.C.
					Third parties	5.97
Corlinter 5000 SLU	Madrid (Spain)	Spain	EUR		13,000 Eni Plen. T. S. Spain	100.00	100.00	F.C.
Cornisa Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Desarrollos Empresariales Illas SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Desarrollos Energéticos Riojanos SL Madrid (Spain)		Spain	EUR		876,042 Eni Plenitude SpA SB Energías Amb. de Outes	60.00 40.00	100.00	F.C.
Ecovent Parc Eolic SAU	Madrid (Spain)	Spain	EUR		1,037,350 Eni Plenitude SpA SB	100.00	100.00	F.C.
Ekain Renovables SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. T. S. Spain	100.00	100.00	F.C.
Energía Eólica Boreas SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Energías Alternativas Eólicas Riojanas SL	Madrid (Spain)	Spain	EUR		2,008,901.71 Eni Plenitude SpA SB	57.50	100.00	F.C.
					Des. Energéticos Riojanos	42.50
Energías Ambientales de Outes SLU	Madrid (Spain)	Spain	EUR		643,451.49 Eni Plenitude SpA SB	100.00	100.00	F.C.
Eni Energy Solutions BV	Amsterdam (Netherlands)	Netherlands	EUR		20,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Eni Gas & Power France SA	Levallois Perret (France)	France	EUR		239,500,800 Eni Plenitude SpA SB Third parties	99.99 ()	100.00	F.C.
Eni New Energy Australia Pty Ltd	Perth (Australia)	Australia	AUD		4 Eni Plenitude SpA	100.00	100.00	F.C.
					SB
Eni New Energy Batchelor Pty Ltd	Perth (Australia)	Australia	AUD		1 Eni New En. Aus. Pty Ltd	100.00	100.00	F.C.
Eni New Energy Katherine Pty Ltd	Perth (Australia)	Australia	AUD		1 Eni New En. Aus. Pty Ltd	100.00	100.00	F.C.
Eni New Energy Manton Dam Pty Ltd	Perth (Australia)	Australia	AUD		1 Eni New En. Aus. Pty Ltd	100.00	100.00	F.C.
Eni New Energy US Holding Llc	Dover (USA)	USA	USD		100 Eni New Energy US Inc	99.00	100.00	F.C.
					Eni New Energy US Inv.Inc	1.00
Eni New Energy US Inc	Dover (USA)	USA	USD		100 Eni Plenitude SpA SB	100.00	100.00	F.C.
Eni New Energy US Investing Inc	Dover (USA)	USA	USD		1,000 Eni New Energy US Inc	100.00	100.00	F.C.
Eni Plenitude Iberia SLU	Santander (Spain)	Spain	EUR		3,192,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Eni Plenitude Investment Colombia SAS (former PLT Colombia SAS)	Bogotà (Colombia)	Colombia	COP		510,840,000 Eni Plen. Wind & En. Srl	51.00	51.00	F.C.
					Third parties	49.00
Eni Plenitude Investment Spain SL (former PLT Spagna SL)	Madrid (Spain)	Spain	EUR		100,000 Eni Plen. Wind & En. Srl Third parties	51.00 49.00	51.00	F.C.
Eni Plenitude Operations France SAS Argenteuil (France) France			EUR		1,116,489.72 Eni Plen. Ren.	100.00	100.00	F.C.
Eni Plenitude Renewables France	Argenteuil (France) France		EUR		Lux. Sàrl 51,000 Eni Plen. Ren.	100.00	100.00	F.C.
SAS Eni Plenitude Renewables Hellas	Athens (Greece)	Greece	EUR		Lux. Sàrl 8,227,464 Eni Plenitude SpA	100.00	100.00	F.C.
Single Member SA					SB

Table of Contents

							Consolidation or
	Registered	Country of		Share		%	% Equity	valutation method
Company name	office	operation	Currency	Capital	Shareholders	Ownership	ratio	(*)
Eni Plenitude Renewables Renewables Luxembourg Sàrl	Luxembourg (Luxembourg)	Luxembourg	EUR		10,253,560 Eni Plenitude SpA SB	100.00	100.00	F.C.
Eni Plenitude Renewables Spain SLU	Madrid (Spain)	Spain	EUR		6,680 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Eni Plenitude Rooftop France SAS	Argenteuil (France)	France	EUR		40,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Eni Plenitude Technical Services Colombia SAS (former PLT Engineering Colombia SAS)	Bogotà (Colombia)	Colombia	COP		1,000,000 Eni Plen. Tech. Serv. Srl Third parties	60.00 40.00	60.00	F.C.
Eni Plenitude Technical Services Romania Srl (former PLT Engineering Romania Srl)	Cluj-Napoca (Romania)	Romania	RON		4,400 Eni Plen. Tech. Serv. Srl Ruggiero Wind Srl	95.00 5.00	100.00	F.C.
Eni Plenitude Technical Services Spain SLU (formerPLTEngineering Spagna SLU)	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Tech. Serv. Srl	100.00	100.00	F.C.
Eolica Cuellar de la Sierra SLU	Madrid (Spain)	Spain	EUR		110,999.77 Eni Plen. Inv. Spain SL	100.00	51.00	F.C.
Estanque Redondo Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Fortaleza Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Fotovoltaica Escudero SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Garita Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Gas Supply Company Thessaloniki Thessalia SA	Thessaloniki (Greece)	Greece	EUR		13,761,788 Eni Plenitude SpA SB	100.00	100.00	F.C.
Guajillo Energy Storage Llc	Dover (USA)	USA	USD		100 Eni New Energy US H. Llc	100.00	100.00	F.C.
Guilleus Consulting SLU	Madrid (Spain)	Spain	EUR		13,000 Eni Plen. T. S. Spain	100.00	100.00	F.C.
HLS Bonete PV SLU	Madrid (Spain)	Spain	EUR		3,602 HLS Bonete Topco SLU	100.00	100.00	F.C.
HLS Bonete Topco SLU	Madrid (Spain)	Spain	EUR		6,602 Eni Plenitude SpA SB	100.00	100.00	F.C.
Holding Lanas Solar Sàrl	Argenteuil (France)	France	EUR		100 Eni Plen. Op. Fr. SAS	100.00	100.00	F.C.
Inveese SAS	Bogotá (Colombia)	Colombia	COP		100,000,000 Eni Plen. Inv. Colombia Third parties	75.00 25.00	38.25	F.C.
Ixia Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Kellam Solar Class B Llc	Dover (USA)	USA	USD		1 Eni New Energy US Inc	100.00	100.00	F.C.
Kellam Tax Equity Partnership Llc	Dover (USA)	USA	USD		41,199,357 Kellam Solar Class B	95.25	95.25	F.C.
					Third parties	4.75
Krypton SAS	Argenteuil (France)	France	EUR		180,000 Eni Plen. Op. Fr. SAS	100.00	100.00	F.C.
Ladronera Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	100.00	100.00	F.C.
Lanas Solar SAS	Argenteuil (France)	France	EUR		100 Holding Lanas Solar Sàrl	100.00	100.00	F.C.
Maristella Directorship SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Spain SLU	100.00	100.00	F.C.
Membrio Solar SLU	Lodosa (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.

Table of Contents

		Country of		Share		%	% Equity	Consolidation or valutation method
Company name Miburia Trade SLU	Registered office Madrid (Spain)	operation Spain	Currency EUR	Capital	Shareholders 13,000 Eni Plen. T. S.	Ownership 100.00	ratio 100.00	(*) F.C.
					Spain
Olea Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen.	100.00	100.00	F.C.
					Ren.Lux. Sàrl
Opalo Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux.Sàrl	100.00	100.00	F.C.
Pistacia Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux.Sàrl	100.00	100.00	F.C.
POP Solar SAS	Argenteuil (France) France		EUR		1,000 Eni Plen. Ren. Lux.Sàrl	100.00	100.00	F.C.
Punes Trade SLU	Madrid (Spain)	Spain	EUR		13,000 Eni Plen. T. S. Spain	100.00	100.00	F.C.
Renopool 1 SLU	Madrid (Spain)	Spain	EUR		3,015 Eni Plen. Ren. Spain SLU	100.00	100.00	F.C.
SKGRPV1 Single Member Private	Athens (Greece)	Greece	EUR		37,600 Eni Plen.	100.00	100.00	F.C.
Company					Renew.Hellas
SKGRPV2 Single Member Private Company	Athens (Greece)	Greece	EUR		39,600 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV3 Single Member Private	Athens (Greece)	Greece	EUR		37,600 Eni Plen.	100.00	100.00	F.C.
Company					Renew.Hellas
SKGRPV4 Single Member Private Company	Athens (Greece)	Greece	EUR		36,600 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV5 Single Member Private	Athens (Greece)	Greece	EUR		22,600 Eni Plen.	100.00	100.00	F.C.
Company					Renew.Hellas
SKGRPV6 Single Member Private Company	Athens (Greece)	Greece	EUR		28,300 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV7 Single Member Private Company	Athens (Greece)	Greece	EUR		66,000 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV8 Single Member Private Company	Athens (Greece)	Greece	EUR		27,200 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV9 Single Member Private	Athens (Greece)	Greece	EUR		27,200 Eni Plen.	100.00	100.00	F.C.
Company					Renew.Hellas
SKGRPV10 Single Member	Athens (Greece)	Greece	EUR		19,800 Eni Plen.	100.00	100.00	F.C.
Private Company					Renew.Hellas
SKGRPV11 Single Member	Athens (Greece)	Greece	EUR		26,300 Eni Plen.	100.00	100.00	F.C.
Private Company					Renew.Hellas
SKGRPV12 Single Member	Athens (Greece)	Greece	EUR		31,000 Eni Plen.	100.00	100.00	F.C.
Private Company					Renew.Hellas
SKGRPV13 Single Member Private Company	Athens (Greece)	Greece	EUR		45,100 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV14 Single Member Private Company	Athens (Greece)	Greece	EUR		121,900 Eni Plen. Renew.Hellas	100.00	100.00	F.C.
SKGRPV15 Single Member	Athens (Greece)	Greece	EUR		39,000 Eni Plen.	100.00	100.00	F.C.
Private Company					Renew.Hellas
SKGRPV16 Single Member	Athens (Greece)	Greece	EUR		32,000 Eni Plen.	100.00	100.00	F.C.
Private Company					Renew.Hellas
SKGRPV17 Single Member	Athens (Greece)	Greece	EUR		50,200 Eni Plen.	100.00	100.00	F.C.
Private Company					Renew.Hellas
SKGRPV18 Single Member Private Company	Athens (Greece)	Greece	EUR		6,200 Eni Plen. Renew.Hellas	100.00	100.00	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
SKGRPV19Single Member Private Company	Athens (Greece)	Greece	EUR		91,400 Eni Plen. Renew. Hellas	100.00	100.00	F.C.
SKGRPV20 Single Member Private Company	Athens (Greece)	Greece	EUR		59,200 Eni Plen. Renew. Hellas	100.00	100.00	F.C.
Tantalio Renovables SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Spain SLU	100.00	100.00	F.C.
Tebar Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.
Wind Grower SLU	Ourense (Spain)	Spain	EUR		593,000 Eni Plen. T. S. Spain	100.00	100.00	F.C.
Wind Hero SLU	Ourense (Spain)	Spain	EUR		563,000 Eni Plen. T. S. Spain	100.00	100.00	F.C.
Xenon SAS	Argenteuil (France) France		EUR		1,500,100 Eni Plen. Op. Fr. SAS Third parties	0.01 (a) 99.99	100.00	F.C.
Zinnia Solar SLU	Madrid (Spain)	Spain	EUR		3,000 Eni Plen. Ren. Lux. Sàrl	100.00	100.00	F.C.

Power

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
EniPower SpA	San Donato Milanese (MI)	Italy	EUR	200,000,000 Eni SpA	Third parties	51.00 49.00	51.00	F.C.
EniPower Mantova SpA	San Donato Milanese (MI)	Italy	EUR	144,000,000 EniPower	SpA Third parties	86.50 13.50	44.12	F.C.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Controlling interest: Eni Plenitude Operations France SAS 100.00

CORPORATE AND OTHER ACTIVITIES

Corporate and financial companies

IN ITALY

Company name	Registered office	Country of operation	Currency		Share Capital Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Agenzia Giornalistica Italia SpA	Rome	Italy	EUR	2,000,000 Eni SpA		100.00	100.00	F.C.
D-Share SpA	Milan	Italy	EUR	121,719.25 AGI SpA		100.00	100.00	F.C.
Eni Corporate University SpA	San Donato Milanese (MI)	Italy	EUR	3,360,000 Eni SpA		100.00	100.00	F.C.
Eni Energia Italia Srl	San Donato Milanese (MI)	Italy	EUR		50,000 Eni SpA	100.00		Co.
Eni Trading & Shipping SpA (in liquidation)	Rome	Italy	EUR		334,171 Eni SpA	100.00		Co.
EniProgetti SpA	Venezia Marghera (VE)	Italy	EUR	2,064,000 Eni SpA		100.00	100.00	F.C.
EniServizi SpA	San Donato Milanese (MI)	Italy	EUR	13,427,419.08 Eni SpA		100.00	100.00	F.C.
Eniverse Ventures Srl	San Donato Milanese (MI)	Italy	EUR	1,550,000 Eni SpA		100.00		Co.
Enivibes Srl	Milan	Italy	EUR	3,552,632 Eniverse	Third parties	76.00 24.00
Servizi Aerei SpA	San Donato Milanese (MI)	Italy	EUR	48,205,536 Eni SpA		100.00	100.00	F.C.

OUTSIDE ITALY

Table of Contents

								Consolidation or
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	valutation method (*)
Banque Eni SA	Bruxelles (Belgium)	Belgium	EUR	50,000,000 Eni	International BV	99.90	100.00	F.C.
					Eni Oil Holdings BV	0.10
Eni Finance USA Inc	Dover (USA)	USA	USD	2,500,000 Eni	Petroleum Co Inc	100.00	100.00	F.C.
Eni Insurance DAC	Dublin (Ireland)	Ireland	EUR	500,000,000 Eni SpA		100.00	100.00	F.C.
Eni International BV	Amsterdam (Netherlands)	Netherlands	EUR	641,683,425 Eni SpA		100.00	100.00	F.C.
Eni International Resources Ltd	London (United Kingdom)	United Kingdom	GBP		50,000 Eni SpA Eni UK Ltd	99.99 ()	100.00	F.C.
Eni Next Llc	Dover (USA)	USA	USD		100 Eni Petroleum Co Inc	100.00	100.00	F.C.
EniProgetti Egypt Ltd	Cairo (Egypt)	Egypt	EGP		50,000 EniProgetti SpA	99.00		Eq.
					Eni SpA	1.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

Other activities

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Eni Rewind SpA	San Donato Milanese (MI)	Italy	EUR	101,755,495.30 Eni SpA	Third parties	99.99 ()	100.00	F.C.
Industria Siciliana Acido Fosforico - ISAF -SpA (in liquidation)	Gela (CL)	Italy	EUR		1,300,000 Eni Rewind SpA Third parties	52.00 48.00		Eq.
Progetto Nuraghe Scarl	Porto Torres (SS)	Italy	EUR		10,000 Eni Rewind SpA	100.00		Eq.

OUTSIDE ITALY

Table of Contents

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Eni Rewind International BV	Amsterdam (Netherlands)	Netherlands	EUR	20,000 Eni	International BV	100.00		Eq.
Oleodotto del Reno SA	Coira (Switzerland)	Switzerland	CHF		1,550,000 Eni Rewind SpA	100.00		Eq.

JOINT ARRANGEMENTS AND ASSOCIATES

EXPLORATION & PRODUCTION

IN ITALY

								Consolidation or
Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	valutation method (*)
Agri-Energy Srl (†)	Jolanda di Savoia (FE)	Italy	EUR		50,000 Eni Natural Energies SpA	50.00		Eq.
					Third parties	50.00
Azule Energy Angola SpA	San Donato	Angola	EUR		20,200,000 Azule Energy	100.00
Mozambique Rovuma Venture SpA (†)	Milanese (MI) San Donato	Mozambique	EUR	20,000,000 Eni SpA	Holdings Ltd	35.71		Eq.
	Milanese (MI)				Third parties	64.29

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Agiba Petroleum Co (†)	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc	Production BV Third parties	50.00 50.00		Co.
Ashrafi Island Petroleum Co (in liquidation)	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc	Production BV Third parties	25.00 75.00		Co.
Azule Energy Angola (Block 18) BV (former BP Angola (Block 18) BV)	Rotterdam (Netherlands)	Angola	EUR		2,275,625.42 Azule Energy Holdings Ltd	100.00
Azule Energy Angola BV (former Eni Angola Exploration BV)	Amsterdam (Netherlands)	Angola	EUR		20,000 Azule Energy Holdings Ltd	100.00
Azule Energy Angola Production BV (former Eni Angola Production BV)	Amsterdam (Netherlands)	Angola	EUR		20,000 Azule Energy Holdings Ltd	100.00
Azule Energy Exploration Angola (KB) Ltd (former BP Exploration Angola (Kwanza Benguela) Ltd)	Sunbury On Thames (United Kingdom)	Angola	USD		1 Azule Energy Holdings Ltd	100.00
Azule Energy Exploration (Angola) Ltd (former BP Exploration (Angola) Ltd)	Sunbury On Thames (United Kingdom)	Angola	USD		1,000,000 Azule Energy Holdings Ltd	100.00
Azule Energy Gas Supply Services Inc	Dover (USA)	USA	USD		1,000 Azule Energy Holdings Ltd	100.00
Azule Energy Holdings Ltd (†)	London (United Kingdom)	United Kingdom	USD	1,000,000 Eni	International BV	50.00		Eq.
Azule Energy Ltd (former Angola JVCO Ltd)	Sunbury On Thames (United Kingdom)	Angola	USD		Third parties 1,000 Azule Energy Holdings Ltd	50.00 100.00
Azule Energy US Gas Llc (former BP Gas Supply (Angola) Llc)	Wilmington (USA)	USA	USD	12,800,000 Azule En.	Gas Sup. S. Inc	100.00
Barentsmorneftegaz Sàrl (†)	Luxembourg (Luxembourg)	Russia	USD		20,000 Eni Energy Russia BV	33.33		Eq.
					Third parties	66.67

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

(†) Jointly controlled entity.

Table of Contents

Consolidation

Company name	Registered office	Country of operation Currency		Share Capital Shareholders	% % Equity Ownership ratio	or valutation method (*)
Cabo Delgado Gas Development Limitad	Maputo (Mozambique)	Mozambique	MZN	2,500,000 Eni Mozamb. LNG H. BV	50.00	Co.
(†)				Third parties	50.00
Cardon IV SA (†)	Caracas (Venezuela)	Venezuela	VED	0 Eni Venezuela BV Third parties	50.00 50.00	Eq.
Compañia Agua Plana SA	Caracas (Venezuela)	Venezuela	VED	0 Eni Venezuela BV Third parties	26.00 74.00	Co.
Coral FLNG SA	Maputo (Mozambique)	Mozambique	MZN	100,000,000 Eni Mozamb. LNG H. BV	25.00	Eq.
				Third parties	75.00
Coral South FLNG DMCC	Dubai (United Arab	United Arab	AED	500,000 Eni Mozamb. LNG H. BV	25.00	Eq.
	Emirates)	Emirates		Third parties	75.00
East Delta Gas Co (in liquidation)	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV Third parties	37.50 62.50	Co.
East Obaiyed Petroleum Co	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV	37.50	Co.
				Third parties	62.50
El Temsah Petroleum Co	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV	25.00	Co.
				Third parties	75.00
EI-Fayrouz Petroleum Co (†) (in	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Exploration BV	50.00
liquidation)				Third parties	50.00
Fedynskmorneftegaz Sarl (†)	Luxembourg (Luxembourg) Russia		USD	20,000 Eni Energy Russia BV	33.33	Eq.
				Third parties	66.67
In Salah Gas Ltd	St. Helier (Jersey)	Algeria	GBP	180 Eni In Salah Ltd	25.56	Co.
				Third parties	74.44
In Salah Gas Services Ltd	St. Helier (Jersey)	Algeria	GBP	180 Eni In Salah Ltd	25.56	Co.
				Third parties	74.44
Isatay Operating Company LIp (†)	Astana (Kazakhstan)	Kazakhstan	KZT	400,000 Eni Isatay Third parties	50.00 50.00	Co.
Karachaganak Petroleum Operating BV	Amsterdam (Netherlands)	Kazakhstan	EUR	20,000 Agip Karachaganak BV	29.25	Co.
				Third parties	70.75
Khaleej Petroleum Co Wll	Safat (Kuwait)	Kuwait	KWD	250,000 Eni Middle E. Ltd	49.00	Eq.
				Third parties	51.00
Liberty National Development Co Llc	Wilmington (USA)	USA	USD	(a) Eni Oil & Gas Inc 0	32.50	Eq.
Mediterranean Gas Co	Cairo (Egypt)	Egypt	EGP	Third parties 20,000 Ieoc Production BV	67.50 25.00	Co.
				Third parties	75.00
Meleiha Petroleum Company	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV	37.50	Co.
				Third parties	62.50
Melitah Oil & Gas BV (†)	Amsterdam (Netherlands)	Libya	EUR	20,000 Eni North Africa BV	50.00	Co.
				Third parties	50.00
Nile Delta Oil Co Nidoco	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV	37.50	Co.
				Third parties	62.50
Norpipe Terminal Holdco Ltd	London (United Kingdom) Norway		GBP	55.69 Eni SpA	14.20	Eq.
North Bardawil Petroleum Co (in	Cairo (Egypt)	Egypt	EGP	Third parties 20,000 Ieoc Exploration BV	85.80 30.00
liquidation)				Third parties	70.00
North El Burg Petroleum Co	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV	25.00	Co.
				Third parties	75.00
North El Hammad Petroleum Co	Cairo (Egypt)	Egypt	USD	20,000 Ieoc Production BV	18.75	Co.
				Third parties	81.25
Petrobel Belayim Petroleum Co (†)	Cairo (Egypt)	Egypt	EGP	20,000 Ieoc Production BV Third parties	50.00 50.00	Co.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

(†) Jointly controlled entity.

Table of Contents

(a) Shares without nominal value.

Consolidation or

		Country of				%	% Equity	valutation
Company name	Registered office	operation	Currency	Share Capital	Shareholders	Ownership	ratio	method (*)
PetroBicentenario SA (†)	Caracas (Venezuela)	Venezuela	VED		0 Eni Lasmo Plc Third parties	40.00 60.00		Eq.
PetroJunín SA (†)	Caracas (Venezuela)	Venezuela	VED		0.02 Eni Lasmo Plc	40.00		Eq.
					Third parties	60.00
PetroSucre SA	Caracas (Venezuela)	Venezuela	VED		0 Eni Venezuela BV	26.00		Eq.
					Third parties	74.00
Pharaonic Petroleum Co	Cairo (Egypt)	Egypt	EGP		20,000 Ieoc Production BV	25.00		Co.
					Third parties	75.00
Port Said Petroleum Co (†)	Cairo (Egypt)	Egypt	EGP		20,000 Ieoc Production BV	50.00		Co.
					Third parties	50.00
QatarEnergy LNG NFE (5) (former Qatar	Doha (Qatar)	Qatar	USD	1,175,885,000 Eni Qatar BV		25.00		Eq.
Liquefied Gas Company Limited (9))					Third parties	75.00
Rovuma LNG Investment (DIFC) Ltd	Dubai (United Arab	Mozambique	USD		50,000 Eni Mozamb. LNG H.	25.00		Eq.
	Emirates)				BV
					Third parties	75.00
Rovuma LNG SA	Maputo (Mozambique) Mozambique		MZN		100,000,000 Eni Mozamb. LNG H.	25.00		Eq.
					BV Third parties	75.00
Shorouk Petroleum Company	Cairo (Egypt)	Egypt	EGP		20,000 Ieoc Production BV	25.00		Co.
					Third parties	75.00
Société Centrale Electrique du Congo SA Pointe-Noire (Republic		Republic of	XAF	44,732,000,000 Eni Congo SAU		20.00		Eq.
	of the Congo)	the Congo			Third parties	80.00
Société Italo Tunisienne d'Exploitation	Tunis (Tunisia)	Tunisia	TND		5,000,000 Eni Tunisia BV	50.00		Eq.
Pétrolière SA (†)
					Third parties	50.00
Sodeps - Société de Developpementet	Tunis (Tunisia)	Tunisia	TND		100,000 Eni Tunisia BV	50.00		Co.
d'Exploitation du Permis du Sud SA (†)					Third parties	50.00
Thekah Petroleum Co (in liquidation)	Cairo (Egypt)	Egypt	EGP		20,000 Ieoc Exploration BV	25.00
					Third parties	75.00
United Gas Derivatives Co	New Cairo (Egypt)	Egypt	USD		153,000,000 Eni International BV	33.33		Eq.
					Third parties	66.67
Vår Energi ASA (#)	Sandnes (Norway)	Norway	NOK		399,425,000 Eni International BV	63.04		Eq.
					Third parties	36.96
VIC CBM Ltd (†)	London (United	Indonesia	USD		52,315,912 Eni Lasmo Plc	50.00		Eq.
	Kingdom)				Third parties	50.00
Virginia Indonesia Co CBM Ltd (†)	London (United Kingdom)	Indonesia	USD		25,631,640 Eni Lasmo Plc Third parties	50.00 50.00		Eq.
West Ashrafi Petroleum Co (†) (in	Cairo (Egypt)	Egypt	EGP		20,000 Ieoc Exploration BV	50.00
liquidation)
					Third parties	50.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

(#) Company with shares quoted on regulated market of extra-EU countries.

(†) Jointly controlled entity.

Table of Contents

GLOBAL GAS & LNG PORTFOLIO

IN ITALY

								Consolidation
								or
		Country of		Share		%	% Equity	valutation
Company name	Registered office	operation	Currency	Capital	Shareholders	Ownership	ratio	method (*)
SeaCorridor Srl (†) (former Eni Corridor	San Donato	Italy	EUR	100,000,000 Eni SpA		50.10		Eq.
Srl)	Milanese (MI)				Third parties	49.90

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Blue Stream Pipeline Co BV (†)	Amsterdam (Netherlands)	Russia	USD	22,000 Eni	International BV Third parties	50.00 50.00	74.62(a)	J.O.
Damietta LNG (DLNG) SAE (†)	Damietta (Egypt)	Egypt	USD	375,000,000 Eni Gas	Liquef. BV Third parties	50.00 50.00	50.00	J.O.
DLNG Service SAE (†)	Damietta (Egypt)	Egypt	USD	1,000,000 Damietta	LNG Eni Gas Liquef. BV Third parties	98.00 1.00 1.00	50.00	J.O.
GreenStream BV (†)	Amsterdam (Netherlands)	Libya	EUR	200,000,000 Eni North	Africa BV Third parties	50.00 50.00	50.00	J.O.
Société Energies Renouvelables Eni ETAP SA (†)	Tunis (Tunisia)	Tunisia	TND	11,100,000 Eni	International BV Third parties	50.00 50.00		Eq.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

Table of Contents

(a) Equity ratio equal to the Eni's working interest.

Table of Contents ENILIVE, REFINING AND CHEMICALS

Enilive and Refining

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Arezzo Gas SpA (†)	Arezzo	Italy	EUR		394,000 Ecofuel SpA Third parties	50.00 50.00		Eq.
CePIM Centro Padano Interscambio Merci SpA	Fontevivo (PR)	Italy	EUR		6,642,928.32 Ecofuel SpA Third parties	44.78 55.22		Eq.
Consorzio Operatori GPL di Napoli	Napoli	Italy	EUR		102,000 Ecofuel SpA Third parties	25.00 75.00		Co.
Costiero Gas Livorno SpA (†)	Livorno	Italy	EUR		26,000,000 Ecofuel SpA Third parties	65.00 35.00	65.00	J.O.
Disma SpA	Segrate (MI)	Italy	EUR		2,600,000 Ecofuel SpA Third parties	25.00 75.00		Eq.
Porto Petroli di Genova SpA	Genova	Italy	EUR		2,068,000 Ecofuel SpA Third parties	40.50 59.50		Eq.
Raffineria di Milazzo ScpA (†)	Milazzo (ME)	Italy	EUR	171,143,000 Eni SpA	Third parties	50.00 50.00	50.00	J.O.
Seram SpA	Fiumicino (RM)	Italy	EUR		852,000 Eni SpA Third parties	25.00 75.00		Eq.
Sigea Sistema Integrato Genova Arquata SpA	Genova	Italy	EUR		3,326,900 Ecofuel SpA Third parties	35.00 65.00		Eq.
Società Oleodotti Meridionali - SOM SpA (†)	Rome	Italy	EUR	3,085,000 Eni SpA	Third parties	70.00 30.00		Eq.
South Italy Green Hydrogen Srl (†)	Rome	Italy	EUR		10,000 Eni SpA Third parties	50.00 50.00		Eq.

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Abu Dhabi Oil Refining Company (TAKREER)	Abu Dhabi (United Arab Emirates)	United Arab Emirates	AED	500,000,000 Eni Abu	Dhabi R&T BV Third parties	20.00 80.00		Eq.
ADNOC Global Trading Ltd	Abu Dhabi (United Arab Emirates)	United Arab Emirates	USD	100,000,000 Eni Abu	Dhabi R&T BV Third parties	20.00 80.00		Eq.
AET - Raffineriebeteiligungsgesellschaft mbH (†)	Schwedt (Germany)	Germany	EUR		27,000 Eni Deutsch. GmbH Third parties	33.33 66.67		Eq.
Bayernoil Raffineriegesellschaft mbH (†) Vohburg (Germany)		Germany	EUR		10,226,000 Eni Deutsch. GmbH Third parties	20.00 80.00	20.00	J.O.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
City Carburoil SA (†)	Monteceneri (Switzerland)	Switzerland	CHF		6,000,000 Eni Suisse SA Third parties	49.91 50.09		Eq.
Egyptian International Gas Technology Co	New Cairo (Egypt)	Egypt	EGP	100,000,000 Eni	International BV Third parties	40.00 60.00		Eq.
ENEOS Italsing Pte Ltd	Singapore (Singapore)	Singapore	SGD	12,000,000 Eni Sust.	Mobility SpA Third parties	22.50 77.50		Eq.
Fuelling Aviation Services GIE	Tremblay - en-France (France)	France	EUR		0 Eni France Sàrl Third parties	25.00 75.00		Co.
Mediterranée Bitumes SA	Tunis (Tunisia)	Tunisia	TND	1,000,000 Eni	International BV Third parties	34.00 66.00		Eq.
Routex BV	Amsterdam (Netherlands)	Netherlands	EUR		67,500 Eni Sust. Mobility SpA Routex BV Third parties	20.00(a) 20.00 60.00		Eq.
Saraco SA	Meyrin (Switzerland)	Switzerland	CHF		420,000 Eni Suisse SA Third parties	20.00 80.00		Co.
St. Bernard Renewables Llc (†)	Wilmington (USA)	USA	USD		1,000 ESM US Inc Third parties	50.00 50.00		Eq.
Supermetanol CA (†)	Jose Puerto La Cruz (Venezuela)	Venezuela	VED		0 Ecofuel SpA Supermetanol CA Third parties	34.51 30.07 35.42	50.00(b)	J.O.
TBG Tanklager Betriebsgesellschaf GmbH (†)	Salzburg (Austria)	Austria	EUR	43,603.70 Eni	Marketing A. GmbH Third parties	50.00 50.00		Eq.
Weat Electronic Datenservice GmbH	Düsseldorf (Germany)	Germany	EUR		409,034 Eni Deutsch. GmbH Third parties	20.00 80.00		Eq.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

	(a) Controlling interest:	Eni Sust. Mobility SpA	25.00
Third parties			75.00

(b) Equity ratio equal to the Eni's working interest.

F-171

Chemicals

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	%	% Equity ratio	Consolidation or valutation method (*)
Brindisi Servizi Generali Scarl	Brindisi	Italy	EUR		1,549,060 Versalis SpA	Ownership 49.00		Eq.
					Eni Rewind SpA	20.20
					EniPower SpA	8.90
					Third parties	21.90
IFM Ferrara ScpA	Ferrara	Italy	EUR		5,304,464 Versalis SpA	19.61		Eq.
					Eni Rewind SpA	11.51
					S.E.F. Srl	10.63
					Third parties	58.25
Polymer Servizi Ecologici Scarl	Terni	Italy	EUR		10,000 Novamont SpA	32.44		Eq.
					Soci Terzi	67.56
Priolo Servizi ScpA	Melilli (SR)	Italy	EUR		28,100,000 Versalis SpA	37.22		Eq.
					Eni Rewind SpA	5.65
					Third parties	57.13
Ravenna Servizi Industriali ScpA	Ravenna	Italy	EUR		5,597,400 Versalis SpA EniPower SpA	42.13 30.37		Eq.
					Ecofuel SpA	1.85
					Third parties	25.65
Servizi Porto Marghera Scarl	Venezia Marghera (VE)	Italy	EUR		8,695,718 Versalis SpA Eni Rewind	48.44 38.39		Eq.
					SpA Third parties	13.17

OUTSIDE ITALY

Table of Contents

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
BioBag Baltic OÜ	Tallinn (Estonia)	Estonia	EUR		3,846 BioBag International Third parties	35.00 65.00		Eq.
Lotte Versalis Elastomers Co Ltd (†)	Yeosu (South Korea) South Korea		KRW	601,800,000,000 Versalis SpA	Third parties	50.00 50.00		Eq.
Versalis Chem-invest Llp (†)	Uralsk City (Kazakhstan)	Kazakhstan	KZT	64,194,000 Versalis	International SA Third parties	49.00 51.00		Eq.
VPM Oilfield Specialty Chemicals Llc (†)	Abu Dhabi (United Arab Emirates)	United Arab Emirates	AED	1,000,000 Versalis	International SA Third parties	49.00 51.00		Eq.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

Table of Contents PLENITUDE & POWER

Plenitude

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Atis Floating Wind Srl (†)	Milan	Italy	EUR		10,000 Eni New Energy SpA Third parties	70.00 30.00		Eq.
Bettercity SpA	Bergamo	Italy	EUR	4,050,000 Eni	Plenitude SpA SB Third parties	50.00 50.00		Eq.
Evogy Srl Società Benefit	Seriate (BG)	Italy	EUR		11,785.71 Evolvere Venture SpA Third parties	45.45 54.55		Eq.
GreenIT SpA (†)	San Donato Milanese (MI)	Italy	EUR	50,000 Eni	Plenitude SpA SB Third parties	51.00 49.00		Eq.
Hergo Renewables SpA (†)	Milan	Italy	EUR	50,000 Eni	Plenitude SpA SB Third parties	65.00 35.00		Eq.
Krimisa Floating Wind Srl (†)	Milan	Italy	EUR		10,000 Eni New Energy SpA Third parties	70.00 30.00		Eq.
Messapia Floating Wind Srl (†)	Milan	Italy	EUR		10,000 Eni New Energy SpA Third parties	70.00 30.00		Eq.
Renewable Dispatching Srl	Milan	Italy	EUR		200,000 Evolvere Venture SpA Third parties	40.00 60.00		Eq.
Siel Agrisolare Srl (†)	Cesena (FC)	Italy	EUR		10,000 Eni Plen. S&M Italia Srl Third parties	51.00 49.00		Eq.
Tate Srl	Bologna	Italy	EUR	408,509.29 Evolvere	Venture SpA Third parties	36.00 64.00		Eq.

OUTSIDE ITALY

Table of Contents

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Bluebell Solar Class A Holdings II Llc	Wilmington (USA)	USA	USD	82,351,634 Eni New	Energy US Inc Third parties	99.00 1.00		Eq.
Clarensac Solar SAS	Fuveau (France)	France	EUR		25,000 Eni Plen. Op. Fr. SAS Third parties	40.00 60.00		Eq.
Enera Conseil SAS (†)	Clichy (France)	France	EUR		9,690 Eni G&P France SA Third parties	51.00 49.00		Eq.
EnerOcean SL (†)	Malaga (Spain)	Spain	EUR	493,320 Eni	Plenitude SpA SB Third parties	37.70 62.30		Eq.
Evacuación San Serván 400 SL (†)	Madrid (Spain)	Spain	EUR		3,000 Renopool 1 SLU Third parties	68.77 31.23		Eq.

Consolidation

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	or valutation method (*)
Guillena 400 Promotores SL (†)	Seville (Spain)	Spain	EUR		3,000 Almazara Solar	6.99		Eq.
					SLU Atlante Solar SLU	6.99
					Chapitel Solar SLU	6.99
					Fortaleza Solar SLU	6.99
					Garita Solar SLU	6.99
					Third parties	65.05
Infraestructuras San Serván SET 400 SL (†)	Madrid (Spain)	Spain	EUR		90,000 Renopool 1 SLU	42.31		Eq.
					Third parties	57.69
Instalaciones San Serván II 400 SL (†) Madrid (Spain)		Spain	EUR		11,026 Renopool 1 SLU	52.38		Eq.
					Third parties	47.62
Novis Renewables Holdings Llc	Wilmington (USA)	USA	USD		100 Eni New Energy US Inc Third parties	49.00 51.00		Eq.
Novis Renewables Llc (†)	Wilmington (USA)	USA	USD		100 Eni New Energy US Inc	50.00		Eq.
					Third parties	50.00
Parc Tramuntana SL (†)	Madrid (Spain)	Spain	EUR		3,500 Eni Plenitude SpA SB	50.00		Eq.
					Third parties	50.00
Parque Eolico Marino La Janda SL (†) Jerez de La Frontera	(Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	50.00		Eq.
					Third parties	50.00
Parque Eolico Marino Nordes SL (†)	Madrid (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	50.00		Eq.
					Third parties	50.00
Parque Eolico Marino Tarahal SL (†)	Las Palmas de Gran Canaria (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	50.00		Eq.
					Third parties	50.00
POW - Polish Offshore Wind-Co Sp zoo (†)	Warsaw (Poland)	Poland	PLN		5,000 Eni Energy Solutions BV	95.00		Eq.
					Third parties	5.00
Promotores Caparacena 400 SL	Madrid (Spain)	Spain	EUR		3,000 Ladronera Solar SLU	8.21		Eq.
					Boceto Solar SLU	7.30
					Cornisa Solar SLU	7.30
					Third parties	77.19
Tramuntana Energy LAB SL (†)	Cerdanyola del Valles (Spain)	Spain	EUR		3,000 Eni Plenitude SpA SB	50.00		Eq.
					Third parties	50.00
Vårgrønn AS (†)	Stavanger (Norway) Norway		NOK		600,000 Eni Energy Solutions BV	65.00		Eq.
					Third parties	35.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

Table of Contents

Power

IN ITALY

								Consolidation
								or
		Country of		Share		%	% Equity	valutation
Company name	Registered office	operation	Currency	Capital	Shareholders	Ownership	ratio	method (*)
Società EniPower Ferrara Srl (†)	San Donato	Italy	EUR	140,000,000 EniPower		51.00	26.01	J.O.
	Milanese (MI)				SpA
					Third parties	49.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

CORPORATE AND OTHER ACTIVITIES

Corporate and financial companies

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital Shareholders		% Ownership	% Equity ratio	Consolidation or valutation method (*)
Consorzio per l'attuazione del Progetto Divertor Tokamak Test DTT Scarl (†)	Frascati (RM)	Italy	EUR	1,000,000 Eni SpA	Third parties	25.00 75.00		Co.
Energy Dome SpA	Milan	Italy	EUR		182,830.21 Eni Next Llc			Eq.
					Third parties
Saipem SpA (#) (†)	Milan	Italy	EUR	501,669,790.83 Eni SpA		31.19(a)		Eq.
					Saipem SpA	0.02
					Third parties	68.79

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
Avanti Battery Company	Natick (USA)	USA	USD		683 Eni Next Llc Third parties			Eq.
Commonwealth Fusion Systems Llc	Wilmington (USA)	USA	USD		904.64 Eni Next Llc CFS Third parties			Eq.
Cool Planet Technologies Ltd	London (United Kingdom)	United Kingdom	GBP		1,000 Eni Next Llc Third parties			Eq.
CZero Inc	Wilmington (USA)	USA	USD		334 Eni Next Llc Third parties			Eq.
Form Energy Inc	Somerville (USA)	USA	USD		1,129 Eni Next Llc Third parties			Eq.
M2X Energy Inc	Wilmington (USA)	USA	USD		99 Eni Next Llc Third parties			Eq.
sHYp BV PBC	Wilmington (USA)	USA	USD		86 Eni Next Llc Third parties			Eq.
Swift Solar Inc	Wilmington (USA)	USA	USD		740.37 Eni Next Llc Third parties			Eq.
Tecninco Engineering Contractors Llp (†)	Aksai (Kazakhstan)	Kazakhstan	KZT		29,478,455 EniProgetti SpA Third parties	49.00 51.00		Eq.
Thiozen Inc	Wilmington (USA)	USA	USD		351 Eni Next Llc Third parties			Eq.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

(#) Company with shares quoted on regulated market of Italy or of other EU countries.

(†) Jointly controlled entity.

Table of Contents

(a) Controlling interest:	Eni SpA	31.20
	Third parties	68.80

Other activities

Table of Contents

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	% Equity ratio	Consolidation or valutation method (*)
HEA SpA (†)	Bologna	Italy	EUR		50,000 Eni Rewind	50.00		Co.
					SpA
					Third parties	50.00
LabAnalysis Environmental Science Srl	San Giovanni	Italy	EUR		100,000 Eni Rewind	30.00		Eq.
(†)	Teatino (CH)				SpA
					Third parties	70.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity.

Table of Contents OTHER SIGNIFICANT INVESTMENTS

EXPLORATION & PRODUCTION

IN ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	Consolidation or valutation method (*)
BF SpA (#)	Jolanda di	Italy	EUR	261,883,391 Eni Natural		5.32	F.V.
	Savoia (FE)				Energies SpA
					Third parties	94.68
Consorzio Universitario in Ingegneria	Pisa	Italy	EUR		142,000 Eni SpA	12.50	F.V.
per la Qualità e l'Innovazione					Third parties	87.50

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	Consolidation or valutation method (*)
Administradora del Golfo de Paria Este SA	Caracas (Venezuela)	Venezuela	VED	0	Eni Venezuela BV Third parties	19.50 80.50	F.V.
Brass LNG Ltd	Lagos (Nigeria)	Nigeria	USD	1,000,000	Eni Int. NA NV Sàrl Third parties	20.48 79.52	F.V.
Darwin LNG Pty Ltd	West Perth (Australia)	Australia	AUD	187,569,921.42	Eni G&P LNG Aus. BV Third parties	10.99 89.01	F.V.
New Liberty Residential Urban Renewal Company Llc (former New Liberty Residential Co Llc)	West Trenton (USA)	USA	USD		0 (a) Eni Oil & Gas Inc Third parties	17.50 82.50	F.V.
Nigeria LNG Ltd	Port Harcourt (Nigeria)	Nigeria	USD	1,138,207,000	Eni Int. NA NV Sàrl Third parties	10.40 89.60	F.V.
North Caspian Operating Company NV	The Hague (Netherlands)	Kazakhstan	EUR	128,520	Agip Caspian Sea BV Third parties	16.81 83.19	F.V.
Petrolera Güiria SA	Caracas (Venezuela)	Venezuela	VED	0	Eni Venezuela BV Third parties	19.50 80.50	F.V.
Torsina Oil Co	Cairo (Egypt)	Egypt	EGP	20,000	Ieoc Production BV Third parties	12.50 87.50	F.V.

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

(#) Company with shares quoted on regulated market of Italy or of other EU countries.

(a) Shares without nominal value.

Table of Contents

GLOBAL GAS & LNG PORTFOLIO

OUTSIDE ITALY

Table of Contents

	Registered	Country of					Consolidation or valutation
Company name	office	operation	Currency	Share Capital	Shareholders	% Ownership	method (*)
Norsea Gas GmbH	Friedeburg-Etzel	Germany	EUR		1,533,875.64 Eni International	13.04	F.V.
	(Germany)				BV
					Third parties	86.96

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.

ENILIVE, REFINING AND CHEMICALS

Enilive and Refining

OUTSIDE ITALY

Table of Contents

	Registered	Country of					Consolidation or valutation
Company name	office	operation	Currency	Share Capital	Shareholders	% Ownership	method (*)
BFS Berlin Fuelling Services GbR	Berlin (Germany) Germany		EUR	89,199	Eni Deutsch. GmbH	12.50	F.V.
					Third parties	87.50
Compañía de Economia Mixta	Cuenca	Ecuador	USD	6,863,493	Eni Ecuador SA	13.38	F.V.
"Austrogas"	(Ecuador)				Third parties	86.62
Dépôt Pétrolier de la Côte d'Azur SAS Nanterre (France) France			EUR	207,500	Eni France Sàrl	18.00	F.V.
					Third parties	82.00
Dépôts Pétroliers de Fos SA	Fos-Sur-Mer	France	EUR	3,954,196.40	Eni France Sàrl	16.81	F.V.
	(France)				Third parties	83.19
Gestión de Envases Comerciales e	Madrid (Spain)	Spain	EUR	3,000	Eni Iberia SLU	16.40	F.V.
Industriales SL					Third parties	83.60
Joint Inspection Group Ltd	Cambourne	United Kingdom	GBP		0(a)Eni Sust.	12.50	F.V.
	(United				Mobility SpA
	Kingdom)				Third parties	87.50
S.I.P.G. Société Immobilière Pétrolière	Tremblay-en	France	EUR	40,000	Eni France Sàrl	12.50	F.V.
de Gestion Snc	France (France)				Third parties	87.50
Saudi European Petrochemical Co	Al Jubail (Saudi	Saudi Arabia	SAR	1,200,000,000	Ecofuel SpA	10.00	F.V.
"IBN ZAHR"	Arabia)				Third parties	90.00
Sistema Integrado de Gestion de	Madrid (Spain)	Spain	EUR	175,713	Eni Iberia SLU	15.45	F.V.
Aceites Usados					Third parties	84.55
Tanklager - Gesellschaft Tegel (TGT)	Hamburg	Germany	EUR	4,953	Eni Deutsch.	12.50	F.V.
GbR	(Germany)				GmbH
					Third parties	87.50
TAR - Tankanlage Ruemlang AG	Ruemlang	Switzerland	CHF	3,259,500	Eni Suisse SA	16.27	F.V.
	(Switzerland)				Third parties	83.73
Tema Lube Oil Co Ltd	Accra (Ghana)	Ghana	GHS	258,309	Eni International	12.00	F.V.
					BV
					Third parties	88.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Shares without nominal value.

CORPORATE AND OTHER ACTIVITIES

Corporate and financial companies

OUTSIDE ITALY

Company name	Registered office	Country of operation	Currency	Share Capital	Shareholders	% Ownership	Consolidation or valutation method (*)
New Energy One Acquisition Corporation Plc (#)	London (United Kingdom)	United Kingdom	GBP	56,220.61 Eni	International BV Third parties		F.V.
Other activities
IN ITALY
	Registered	Country of					Consolidation or valutation
Company name	office	operation	Currency	Share Capital	Shareholders	% Ownership	method (*)
Ottana Sviluppo ScpA (in bankruptcy)	Nuoro	Italy	EUR		516,000 Eni Rewind SpA	30.00	F.V.
					Third parties	70.00

(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (#) Company with shares quoted on regulated market of extra-EU countries.

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 the EniPower group 51% owned by Eni. The ownership of the non controlling interest corresponds to voting rights.

	2023 EniPower	2022 EniPower
(€ million)	Group	Group
Non controlling interest (%)	49.00	49.00
Current assets	374	547
Non-current assets	868	812
Current liabilities	389	587
Non-current liabilities	46	34
Revenues	1,251	1,636
Profit	169	171
Total comprehensive income	169	171
Net cash provided by operating activities	198	228
Net cash used in investing activities	(126)	(52)
Net cash used in financing activities	(3)	(11)
Net increase (decrease) in cash and cash equivalents	(31)	(192)
Profit attributable to non-controlling interest	86	54
Dividends paid to minority interest	36	59

Equity pertaining to non-controlling interests as of December 31, 2023, amounted to €460 million (€471 million December 31, 2022).

Changes in the ownership interest without loss of control

In 2023, Eni purchased the entirety of third-party interests (29.48%) of the company Evolvere SpA Società Benefit for a total consideration of €60 million.

In 2022, Eni sold 49% of the capital of the subsidiary EniPower SpA with a gain of €542 million.

Principal joint ventures, joint operations and associates as of December 31, 2023

Company name	Country of Registered office operation Segment			% ownership	% equity ratio
Joint venture
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
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	31.19	31.20
SeaCorridor Srl	San Donato Milanese (MI) (Italy)	Italy	Global Gas & LNG Portfolio	50.10	50.10
St. Bernard Renewables Llc	Wilmington (USA)	USA	Enilive and Refining	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
Raffineria di Milazzo ScpA	Milazzo (ME) (Italy)	Italy	Enilive and Refining	50.00	50.00
Associates
ADNOC Global Trading	Abu Dhabi (United	United Arab	Enilive and	20.00	20.00
Ltd	Arab Emirates)	Emirates	Refining
Abu Dhabi Oil Refining Company (Takreer)	Abu Dhabi (United Arab Emirates)	United Arab Emirates	Enilive and Refining	20.00	20.00
Coral FLNG SA	Maputo (Mozambique)	Mozambique	Exploration & Production	25.00	25.00
QatarEnergy LNG NFE (5)	Doha (Qatar)	Qatar	Exploration &	25.00	25.00
(former Qatar Liquefied Gas Company Limited (9))			Production
Vår Energi ASA	Sandnes (Norway)	Norway	Exploration & Production	63.04	63.04

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:

2023
	Azule	St. Bernard Renewables
(€ million)	Energy Holdings Ltd	Llc	Saipem SpA	SeaCorridor Srl	Other joint ventures
Current assets	3,554	317	8,104	165	1,701
- of which cash and cash
equivalent	546	65	2,136	104	551
Non-current assets	19,976	1,594	4,737	964	15,174
Total assets	23,530	1,911	12,841	1,129	16,875
Current liabilities	2,360	134	6,857	55	2,242
- of which current financial
liabilities			97		85
Non-current liabilities	11,670	119	3,588	16	11,671
- of which non-current financial
liabilities	4,239	119	2,599	1	10,140
Total liabilities	14,030	253	10,445	71	13,913
Net equity	9,500	1,658	2,396	1,058	2,962
Eni's % of the investment	50.00	50.00	31.20	50.10
Book value of the investment	4,750	829	722	530	1,420
Revenues and other income	5,125	591	11,898	456	2,500
Operating expense	(814)	(598)	(10,967)	(42)	(1,445)
Other operating profit (loss)		(45)	(5)		(2)
Depreciation, amortization and
impairments	(2,560)	(28)	(489)	(43)	(556)
Operating profit (loss)	1,751	(80)	437	371	497
Finance income (expense)	(373)	(4)	(167)	(3)	(356)
Income (expense) from
investments	332		60	33	(23)
Profit (loss) before income
taxes	1,710	(84)	330	(401)	118
Income taxes	(404)		(145)	(303)	(122)
Profit (loss)	1,306	(84)	185	98	(4)
Other comprehensive income
(loss)	(295)	(22)	59	(8)	(105)
Total other comprehensive
income (loss)	1,011	(106)	244	90	(109)
Profit (loss) attributable to Eni	653	(42)	56	49	(55)
Dividends received from the
joint venture	829			95	15
		F-184

2022 (€ million) Azule Energy Holdings Ltd Saipem SpA Cardón IV SA Other joint ventures Current assets 3,869 7,627 425 741 - of which cash and cash equivalent 966 2,052 7 219 Non-current assets 21,281 4,770 1,812 13,639 Total assets 25,150 12,397 2,237 14,380 Current liabilities 2,635 6,932 431 1,764 - of which current financial liabilities 159 1,040 3 1,278 Non-current liabilities 12,369 3,352 940 10,740 - of which non-current financial liabilities 4,403 1,993 43 10,146 Total liabilities 15,004 10,284 1,371 12,504 Net equity 10,146 2,113 866 1,876 Eni's % of the investment 50.00 31.20 50.00 Book value of the investment 5,073 645 433 915 Revenues and other income 2,422 9,991 942 526 Operating expense (956) (9,455) (679) (463) Other operating profit (loss) 7 25 Depreciation, amortization and impairments (1,099) (445) (127) (258) Operating profit (loss) 367 98 136 (170) Finance income (expense) (142) (195) (167) Income (expense) from investments 718 (65) (4) Profit (loss) before income taxes 943 (162) (136) (341) Income taxes (33) (153) (122) 62 Profit (loss) - discontinued operations 106 Profit (loss) 910 (209) 14 (279) Other comprehensive income (loss) (516) 24 30 119 Total other comprehensive income (loss) 394 (185) 44 (160) Profit (loss) attributable to Eni 455 (82) 7 7 Dividends received from the joint venture 475 8

The results for the year and the comprehensive income of the significant joint ventures are shown below:

		2023
	Mozambique Rovuma
(€ million)	Venture SpA	Cardón IV SA	Vårgrønn AS
Profit (loss)	131	(28)	(77)
Other comprehensive income (loss)	(35)	(30)	(39)
Total other comprehensive income (loss)	96	(58)	(116)

	2022
(€ million)	Vårgrønn AS	Mozambique Rovuma Venture SpA
Profit (loss)	(17)	(202)
Other comprehensive income (loss)	(7)	72
Total other comprehensive income (loss)	(24)	(130)

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:

2023
	Abu Dhabi Oil
	Refining Company	Vår Energi	QatarEnergy	Other
(€ million)	(Takreer)	ASA	LNG NFE (5)	associates
Current assets	3,506	1,502		6,209
- of which cash and cash equivalent	196	665		472
Non-current assets	17,036	15,784	1,884	13,791
Total assets	20,542	17,286	1,884	20,000
Current liabilities	648	1,843	83	5,738
- of which current financial liabilities				551
Non-current liabilities	7,722	14,734	44	9,860
- of which non-current financial liabilities	4,972	3,586		9,723
Total liabilities	8,370	16,577	127	15,598
Net equity	12,172	709	1,757	4,402
Eni's % of the investment	20.00	63.04	25.00
Book value of the investment	2,434	447	439	1,001
Revenues and other income	29,259	6,335		36,559
Operating expense	(26,459)	(1,242)	(18)	(36,070)
Other operating income (expense)	(738)			(168)
Depreciation, amortization and impairments	(426)	(1,840)		(73)
Operating profit (loss)	1,636	3,253	(18)	248
Finance income (expense)	(154)	(148)	3	(111)
Income (expense) from investments				43
Profit (loss) before income taxes	1,482	3,105	(15)	180
Income taxes		(2,541)	4	13
Profit (loss)	1,482	564	(11)	193
Other comprehensive income (loss)	(412)	(48)	(55)	(153)
Total other comprehensive income (loss)	1,070	516	(66)	40
Profit (loss) attributable to Eni	296	356	(3)	22
Dividends received from the associate	277	640		143

2022 (€ million) Abu Dhabi Oil Refining Company (Takreer) Vår Energi ASA Coral FLNG SA Other associates Current assets 3,730 1,612 578 4,828 - of which cash and cash equivalent 150 417 25 284 Non-current assets 17,896 15,821 7,386 8,830 Total assets 21,626 17,433 7,964 13,658 Current liabilities 2,681 3,044 695 4,220 - of which current financial liabilities 561 1 411 Non-current liabilities 6,458 13,179 5,949 4,220 - of which non-current financial liabilities 5,366 2,404 5,926 4,056 Total liabilities 9,139 16,223 6,644 8,440 Net equity 12,487 1,210 1,320 5,218 Eni's % of the investment 20.00 63.08 25.00 Book value of the investment 2,497 763 330 1,381 Revenues and other income 36,240 9,520 59 37,846 Operating expense (32,916) (1,280) (49) (36,754) Other operating income (expense) (702) (10) Depreciation, amortization and impairments (741) (1,881) (4) (247) Operating profit (loss) 1,881 6,359 6 835 Finance income (expense) (83) (495) 553 (14) Income (expense) from investments 3 Profit (loss) before income taxes 1,798 5,864 559 824 Income taxes (4,768) 1 (26) Profit (loss) 1,798 1,096 560 798 Other comprehensive income (loss) 646 (144) 29 (81) Total other comprehensive income (loss) 2,444 952 589 717 Profit (loss) attributable to Eni 360 691 140 411 Dividends received from the associate 142 469 97

The results for the year and the comprehensive income of the significant associates are shown below:

	2023
	ADNOC
	Global	Coral FLNG
(€ million)	Trading Ltd	SA
Profit (loss)	602	(161)
Other comprehensive income (loss)	(27)	(38)
Total other comprehensive income (loss)	575	(199)

		2022
		Qatar
		Liquefied
	ADNOC	Gas
	Global	Company	Novamont
(€ million)	Trading Ltd	Limited (9)	SpA
Profit (loss)	849		(152)
Other comprehensive income (loss)	5	(16)	(107)
Total other comprehensive income (loss)	854	(16)	(259)

<-- PDF CHUNK SEPARATOR -->

38 Significant non-recurring events and operations

In 2023, in 2022 and 2021, Eni did not report any non-recurring events and operations.

39 Positions or transactions deriving from atypical and/or unusual operations

In 2023, in 2022 and 2021, no transactions deriving from atypical and/or unusual operations were reported.

40 Subsequent events

On January 31, 2024, Eni finalized the acquisition of 100% of Neptune Energy Group, a group based in the United Kingdom and active in the research, development and production of hydrocarbons, mainly natural gas assets in Indonesia, Algeria and United Kingdom. The transaction, which implies an outlay for Eni of approximately €2 billion, was conducted in agreement with the associate Vår Energi ASA which acquired Neptune's assets in Norway. Price allocation to the net assets acquired is underway.

In March 2024, Eni Plenitude SpA Società Benefit finalized an agreement with Energy Infrastructure Partners (EIP) which allowed EIP to enter the share capital of Plenitude through a capital increase of €0.6 billion, equal to 7.6% of the Company's share capital.

$$\text{F-190}$$

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)

		Rest of	North		Sub - Saharan		Rest		Australia and
2023	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Proved property	19,073	6,802	17,812	22,617	30,058	13,360	13,048	19,106	1,608	143,484
Unproved property	22	325	603	48	2,280	7	1,480	859	197	5,821
Support equipment and facilities	310	27	1,596	272	1,102	128	12	24	12	3,483
Incomplete wells and
other	1,006	354	1,319	827	2,510	1,062	1,834	511	83	9,506
Gross Capitalized Costs	20,411	7,508	21,330	23,764	35,950	14,557	16,374	20,500	1,900	162,294
Accumulated depreciation, depletion and amortization	(16,515)	(6,390)	(15,880)	(16,679)	(24,796)	(4,578)	(10,853)	(16,042)		(1,060) (112,793)
Net Capitalized Costs consolidated
subsidiaries (a) (c)	3,896	1,118	5,450	7,085	11,154	9,979	5,521	4,458	840	49,501
Equity-accounted
entities
Proved property		8,585	119		27,267		278	2,030		38,279
Unproved property		835			69					904
Support equipment and facilities		50	8		257			7		322
Incomplete wells and
other		3,790	9		1,823		193	233		6,048
Gross Capitalized Costs		13,260	136		29,416		471	2,270		45,553
Accumulated depreciation, depletion and
amortization Net Capitalized		(4,364)	(73)		(20,707)			(1,480)		(26,624)
Costs equity accounted entities
(a) (b)		8,896	63		8,709		471	790		18,929
					F-191

(€ million)

					Sub -				Australia
		Rest of	North		Saharan		Rest		and
2022	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Proved property	18,687	6,629	17,490	22,969	29,784	13,705	12,846	19,192	1,480	142,782
Unproved property	22	330	613	44	2,411	7	1,462	931	204	6,024
Support equipment
and facilities	309	24	1,645	270	1,128	132	13	24	12	3,557
Incomplete wells and other	767	237	1,282	543	1,970	936	1,457	379	115	7,686
Gross Capitalized
Costs	19,785	7,220	21,030	23,826	35,293	14,780	15,778	20,526	1,811	160,049
Accumulated depreciation, depletion and
amortization	(15,677)	(6,214)	(15,949)	(16,212)	(25,024)	(4,147)	(10,133)	(15,341)		(1,001) (109,698)
Net Capitalized Costs consolidated
subsidiaries (a)	4,108	1,006	5,081	7,614	10,269	10,633	5,645	5,185	810	50,351
Equity-accounted entities
Proved property		7,387	118		27,959		287	2,100		37,851
Unproved property		996			91					1,087
Support equipment and facilities		31	8		262			8		309
Incomplete wells and
other		3,872	9		1,530		48	241		5,700
Gross Capitalized
Costs		12,286	135		29,842		335	2,349		44,947
Accumulated depreciation,
depletion and
amortization		(3,492)	(68)		(20,280)			(1,466)		(25,306)
Net Capitalized
Costs equity
accounted entities (a) (b)		8,794	67		9,562		335	883		19,641

(a) The amounts include net capitalized financial charges totalling €709 million in 2023 and €725 million in 2022 for the consolidates

subsidiaries and €658 million in 2023 and €565 million in 2022 for equity-accounted entities. (b) Includes allocation at fair value of the assets of Azule Energy Holdings Ltd.

(c) Includes allocation at fair value of the assets of the companies acquired by Chevron in Indonesia and by BP in Algeria.

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)

					Sub -				Australia
		Rest of	North		Saharan		Rest		and
2023	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	12	55	91	237	189	9	277	138	1	1,009
Development (a)	798	249	925	708	2,662	296	921	937	151	7,647
Total costs incurred consolidated subsidiaries	810	304	1,016	945	2,851	305	1,198	1,075	152	8,656
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
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
F-193

(€ million)

					Sub -				Australia
		Rest of	North		Saharan		Rest		and
2022	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Proved property
acquisitions	4		51					82		137
Unproved property
acquisitions	2		111		11					124
Exploration	12	101	68	179	295	4	253	26	1	939
Development (a)	216	(129)	343	795	1,458	277	835	1,292	117	5,204
Total costs incurred
consolidated
subsidiaries	234	(28)	573	974	1,764	281	1,088	1,400	118	6,404
Equity-accounted entities
Proved property acquisitions							291			291
Unproved property
acquisitions
Exploration		73			13					86
Development (b)		1,690	(8)		125		49	(9)		1,847
Total costs incurred
equity-accounted
entities		1,763	(8)		138		340	(9)		2,224
2021
Consolidated subsidiaries
Proved property
acquisitions								8		8
Unproved property
acquisitions			6					3		9
Exploration	16	96	33	57	136	3	188	83	1	613
Development (a)	182		497	452	842	185	785	657	27	3,627
Total costs incurred
consolidated
subsidiaries	198	96	536	509	978	188	973	751	28	4,257
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		92								92
Development (b)
Total costs incurred		936	59		4			2		1,001
equity-accounted
entities		1,028	59		4			2		1,093

(a) Includes the abandonment costs for €773 million in 2023, decrease of the assets for €307 million in 2022, costs €62 million in 2021.

(b) Includes the abandonment costs for €163 million in 2023, decrease of the assets for €111 million in 2022, decrease for €464 million in 2021.

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)
2023	Italy	Rest of Europe	North Africa	Egypt	Sub - Saharan Africa	Kazakhstan	Rest of Asia	America	Australia and Oceania	Total
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	4,032	3,904	903	897	532	135	51	10,472
Total revenues	1,475	880	5,509	3,904	2,648	2,742	3,502	1,796	52	22,508
Production costs	(348)	(202)	(518)	(434)	(656)	(267)	(304)	(469)	(25)	(3,223)
Transportation costs	(3)	(43)	(59)	(9)	(10)	(178)	(6)	(19)		(327)
Production taxes	(152)		(300)		(294)		(326)	(73)		(1,145)
Exploration expenses	(12)	(14)	(82)	(163)	(121)	(2)	(140)	(152)	(1)	(687)
D.D. & A. and Provision
for abandonment (a)	(886)	(166)	(923)	(1,056)	(716)	(601)	(1,093)	(1,531)	(95)	(7,067)
Other income (expenses)	(347)	(117)	58	(418)	(128)	(148)	(263)	(108)	(7)	(1,478)
Pretax income from
producing activities	(273)	338	3,685	1,824	723	1,546	1,370	(556)	(76)	8,581
Income taxes	169	(292)	(2,498)	(870)	(391)	(503)	(1,150)	369	19	(5,147)
Results of operations from E&P activities of consolidated
subsidiaries	(104)	46	1,187	954	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.

(€ million)

					Sub -				Australia
		Rest of	North		Saharan		Rest		and
2022	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Revenues:
- sales to consolidated
entities	1,952	1,854	2,095		4,434	1,602	2,982	1,683	3	16,605
- sales to third parties	329	23	3,946	4,897	1,216	1,001	837	307	72	12,628
Total revenues	2,281	1,877	6,041	4,897	5,650	2,603	3,819	1,990	75	29,233
Production costs	(387)	(189)	(486)	(484)	(871)	(241)	(326)	(410)	(21)	(3,415)
Transportation costs	(3)	(42)	(50)	(5)	(29)	(147)	(3)	(16)		(295)
Production taxes	(286)		(330)		(478)		(421)	(63)		(1,578)
Exploration expenses	(11)	(25)	(162)	(106)	(150)	(6)	(123)	(21)	(1)	(605)
D.D. & A. and Provision
for abandonment (a)	(449)	(158)	(839)	(1,156)	(1,488)	(434)	(727)	(707)	(90)	(6,048)
Other income (expenses)	(1,987)	(98)	1,955	(378)	(196)	(127)	(292)	2	(4)	(1,125)
Pretax income from
producing activities	(842)	1,365	6,129	2,768	2,438	1,648	1,927	775	(41)	16,167
Income taxes	337	(665)	(2,740)	(1,192)	(979)	(524)	(1,457)	(41)	47	(7,214)
Results of operations from E&P activities of
consolidated subsidiaries	(505)	700	3,389	1,576	1,459	1,124	470	734	6	8,953
Equity-accounted entities
Revenues:
- sales to consolidated
entities		2,937			572					3,509
- sales to third parties		3,039	14		1,327			533		4,913
Total revenues		5,976	14		1,899			533		8,422
Production costs		(567)	(6)		(244)			(24)		(841)
Transportation costs		(131)	(1)		(9)					(141)
Production taxes			(2)		(15)			(123)		(140)
Exploration expenses		(44)			(7)		(13)			(64)
D.D. & A. and Provision
for abandonment		(1,121)	(6)		(628)		(1)	(63)		(1,819)
Other income (expenses)		(64)			(271)		1	(234)		(568)
Pretax income from
producing activities		4,049	(1)		725		(13)	89		4,849
Income taxes		(3,076)	3		(21)			(105)		(3,199)
Results of operations from E&P activities of equity-accounted
entities		973	2		704		(13)	(16)		1,650

(a) Includes asset net impairment amounting to €279 million.

		Rest of	North		Sub - Saharan		Rest		Australia and
2021	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Revenues:
- sales to consolidated
entities	1,680	790	1,133		3,782	1,391	2,020	734	4	11,534
- sales to third parties		36	2,602	3,637	930	704	380	351	108	8,748
Total revenues	1,680	826	3,735	3,637	4,712	2,095	2,400	1,085	112	20,282
Production costs	(326)	(147)	(581)	(399)	(816)	(211)	(251)	(288)	(17)	(3,036)
Transportation costs	(4)	(35)	(45)	(10)	(20)	(150)	(5)	(11)		(280)
Production taxes	(128)		(192)		(379)		(230)	(28)		(957)
Exploration expenses D.D. & A. and Provision	(16)	(72)	(27)	(47)	(238)	(1)	(135)	(21)	(1)	(558)
for abandonment (a)	(31)	(196)	(357)	(990)	(1,468)	(431)	(665)	(243)	(69)	(4,450)
Other income (expenses)	(395)	11	557	(310)	(330)	(120)	(173)	(132)	(2)	(894)
Pretax income from producing activities	780	387	3,090	1,881	1,461	1,182	941	362	23	10,107
Income taxes	(198)	(156)	(1,450)	(848)	(708)	(394)	(739)	(17)	(15)	(4,525)
Results of operations from E&P activities of consolidated
subsidiaries	582	231	1,640	1,033	753	788	202	345	8	5,582
Equity-accounted entities
Revenues:
- sales to consolidated
entities		1,831								1,831
- sales to third parties		1,756	12		365			367		2,500
Total revenues		3,587	12		365			367		4,331
Production costs		(388)	(6)		(25)			(15)		(434)
Transportation costs		(140)	(1)		(12)					(153)
Production taxes			(2)		(112)			(88)		(202)
Exploration expenses D.D. & A. and Provision		(35)								(35)
for abandonment		(879)	(3)		42			(154)		(994)
Other income (expenses)		(287)			(158)		(1)	(197)		(643)
Pretax income from
producing activities		1,858			100		(1)	(87)		1,870
Income taxes		(1,237)						(66)		(1,303)
Results of operations from E&P activities of
equity-accounted entities		621			100		(1)	(153)		567

(a) Includes asset net reversal amounting to €1,263 million.

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 un-weighted 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 2023, the average price for the marker Brent crude oil was \$83 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.

Eni has its proved reserves evaluated on a rotational basis by independent oil engineering companies¹ . The description of qualifications of the person primarily responsible of the reserves audit is included in the third-party audit report² . 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 Eni³ .

In 2023, an independent evaluation of about 34%⁴ of Eni's total proved reserves as of December 31, 2023, confirming, as in previous years, the reasonableness of Eni's internal evaluations.

In the three-year period from 2021 to 2023, 77% 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 55%, 54% and 58% of total proved reserves as of December 31, 2023, 2022 and 2021 respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves associated with such contracts represented 2%, 2%, and 3% of total proved reserves on an oil-equivalent basis as of December 31, 2023, 2022 and 2021, respectively.

²⁹For the past three years we have availed of the independent certification service of DeGolyer and Mac Naughton, Ryder Scott, Société Générale de Surveillance and Sproule.

³⁰The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2023.

³¹In 2023 and 2022 Azule and Vår Energi.

³²Includes Eni's share of proved reserves of equity accounted entities.

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 2%, 3% and 4% of total proved reserves as of December 31, 2023, 2022 and 2021, respectively, on an oil equivalent basis; (ii) volumes of proved reserves of natural gas to be consumed in operations amounted to 2,338 BCF at 2023 year-end (2,389 BCF and 2,335 BCF respectively at 2022 and 2021 year-end); (iii) the quantities of hydrocarbons related to the Angola LNG plant owned by the JV Azule set up 50% with bp during the year.

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, 2023 totalled 2,419 mmboe, of which 1,109 mmboe of liquids and 1,310 mmboe of natural gas particularly located in Africa and Asia. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,662 mmboe (of which 740 mmboe of liquids and 992 mmboe of natural gas). Changes in proved undeveloped reserves were as follows:

(mmboe)

Proved undeveloped reserves as of December 31, 2022	2,423
Transfer to proved developed reserves	(187)
Extensions and discoveries	104
Revisions of previous estimates	121
Improved recovery	0
Portfolio	(42)
Proved undeveloped reserves as of December 31, 2023	2,419

In 2023, total proved undeveloped reserves decreased by 4 mmboe (proved undeveloped reserves of consolidated companies increased by 31 mmboe, while those of joint ventures and associates decreased by 35 mmboe).

Main changes derived from:

i) proved undeveloped reserves matured to proved developed reserves amounted to -187 mmboe, and were driven by progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to: Vår Energi (-63 mmboe) mainly in the fields of Breidablikk, Fenja, Tommeliten Alpha, Bauge and Frosk; Ivory Coast (-26 mmboe) in the Baleine field; Egypt (-24 mmboe) mainly in the fields of Zohr and Meleiha; Messico (-14 mmboe) in the Amoca and Mizton fields;

ii) new discoveries and extensions of +104 mmboe: (i) an increase of 50 mmboe of liquids, mainly related to the investment decision for the Hail and Ghasha projects in United Arab Emirates; (ii) and from an increase of +54 mmboe of gas, mainly related to to the investment decision for the Hail and Ghasha projects in United Arab Emirates (+42 mmboe) and Merakes East in Indonesia (+11 mmboe);

iii) revisions of previous estimates (+121 mmboe) (including the effect of updating the gas conversion factor by +8 mmboe), of which 107 mmbbl of oil and 33 BCF of natural gas. Positive revisions mainly related to the advancement of development activities in Libya (+104 mmboe) mainly in Area D and Bouri, in Italy (+39 mmboe) especially in the Val d'Agri, and in Vår Energi (38 mmboe). Negative revisions mainly refer to a reduction in Egypt (-86 million boe) mainly on the Belayim field and for the reconfiguration of the Zohr phase 2 project;

iv) portfolio operations (-42 million boe), mainly relate to the sale of Alliance assets in the United States and from a reduction of share in the Ghasha concession in the United Arab Emirates.

Proved reserves of crude oil (including condensate and natural gas liquids)

(million barrels)

					Sub -		Rest		Australia
2023	Italy	Rest of Europe	North Africa	Egypt	Saharan Africa	Kazakhstan	of Asia	America	and Oceania	Total
Consolidated subsidiaries
Reserves at
December 31, 2022	188	36	364	167	367	644	433	234	1	2,434
of which: developed	139	32	201	135	212	585	231	171	1	1,707
undeveloped	49	4	163	32	155	59	202	63		727
Purchase of Minerals in Place			4							4
Revisions of Previous Estimates	34	(2)	61	(3)	(2)	35	35	3	(1)	160
Improved Recovery
Extensions and
Discoveries							50			50
Production	(11)	(7)	(45)	(25)	(31)	(42)	(31)	(24)		(216)
Sales of Minerals in Place							(2)			(2)
Reserves at
December 31, 2023	211	27	384	139	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	390	139	541	637	595	239		3,105
Developed	136	191	210	122	332	576	240	189		1,996
consolidated subsidiaries	136	24	204	122	225	576	240	163		1,690
equity-accounted entities		167	6		107			26		306
Undeveloped	75	162	180	17	209	61	355	50		1,109
consolidated subsidiaries	75	3	180	17	109	61	245	50		740
equity-accounted entities		159			100		110			369

(million barrels)

		Rest of	North		Sub - Saharan		Rest of		Australia and
2022	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	America	Oceania	Total
Consolidated subsidiaries
Reserves at
December 31, 2021	197	34	393	210	589	710	476	237	1	2,847
of which: developed	146	34	225	164	435	641	262	164	1	2,072
undeveloped	51		168	46	154	69	214	73		775
Purchase of Minerals in Place	1		17					2		20
Revisions of Previous Estimates	3	6	(8)	(16)	(62)	(34)	(15)	13		(113)
Improved Recovery			2					4		6
Extensions and
Discoveries		3	5	1	61					70
Production	(13)	(7)	(45)	(28)	(51)	(32)	(28)	(22)		(226)
Sales of Minerals in Place					(170)					(170)
Reserves at
December 31, 2022	188	36	364	167	367	644	433	234	1	2,434
Equity-accounted entities
Reserves at December 31, 2021		378	9		21			6		414
of which: developed		175	9		9			6		199
undeveloped		203			12					215
Purchase of Minerals in Place					132		100			232
Revisions of Previous Estimates		38			37			22		97
Improved Recovery					4					4
Extensions and
Discoveries		4			54					58
Production		(33)	(1)		(13)			(1)		(48)
Sales of Minerals in
Place		(37)								(37)
Reserves at December 31, 2022		350	8		235		100	27		720
Reserves at December
31, 2022	188	386	372	167	602	644	533	261	1	3,154
Developed	139	205	209	135	347	585	231	198	1	2,050
consolidated subsidiaries	139	32	201	135	212	585	231	171	1	1,707
equity-accounted entities		173	8		135			27		343
Undeveloped	49	181	163	32	255	59	302	63		1,104
consolidated subsidiaries	49	4	163	32	155	59	202	63		727
equity-accounted entities		177			100		100			377

		Rest of	North	Egypt	Sub - Saharan		Rest of Asia		Australia and
2021	Italy	Europe	Africa		Africa	Kazakhstan		America	Oceania	Total
Consolidated subsidiaries Reserves at
December 31, 2020	178	34	383	227	624	805	579	224	1	3,055
of which: developed	146	31	243	172	469	716	297	143	1	2,218
undeveloped	32	3	140	55	155	89	282	81		837
Purchase of Minerals in Place								1		1
Revisions of Previous
Estimates	32	8	49	11	21	(58)	(74)	21		10
Improved Recovery					2			10		12
Extensions and
Discoveries		(1 )	6	2	16					23
Production	(13)	(7 )	(45)	(30)	(72)	(37)	(29)	(19)		(252)
Sales of Minerals in Place					(2 )					(2 )
Reserves at
December 31, 2021	197	34	393	210	589	710	476	237	1	2,847
Equity-accounted entities
Reserves at
December 31, 2020		400	12		18			30		460
of which: developed		176	12		15			30		233
undeveloped		224			3					227
Purchase of Minerals in Place
Revisions of Previous Estimates		17	(2 )		4			(23)		(4 )
Improved Recovery
Extensions and Discoveries		2								2
Production		(41)	(1 )		(1 )			(1 )		(44)
Sales of Minerals in Place
Reserves at December 31, 2021		378	9		21			6		414
Reserves at December 31, 2021	197	412	402	210	610	710	476	243	1	3,261
Developed	146	209	234	164	444	641	262	170	1	2,271
consolidated subsidiaries	146	34	225	164	435	641	262	164	1	2,072
equity-accounted entities		175	9		9			6		199
Undeveloped	51	203	168	46	166	69	214	73		990
consolidated subsidiaries	51		168	46	154	69	214	73		775
equity-accounted entities		203			12					215

Main changes in proved reserves of crude oil (including condensates and natural gas liquids) reported in the tables above for the period 2023, 2022 and 2021 are discussed below.

Consolidated subsidiaries

Purchase of Minerals in Place

In 2021, there are two acquisitions (totaling 1 mmboe) of Lucius fields in the U.S. and Conwy in the U.K.

In 2022, 20 mmbbl were booked, mainly for the acquisition of the BHP share in Algeria and a share in some fields in the United States Gulf of Mexico.

In 2023 we have an acquisition of some BP assets in Algeria for 4 mmbbl.

Revisions of Previous Estimates

In 2021, revisions of previous estimates were 10 mmbbl detailed as follows. In Italy there were positive revisions of 32 mmbbl mainly due to the Val d'Agri project. In the Rest of Europe 8 mmbbl of positive revisions were registered, mainly in the United Kingdom. In the Rest of North Africa revisions totaled 49 mmbbl, comprising positive revisions (+62 mmbbl) of which +42 mmbbl in Libya (mainly in Area D) and +18 mmbbl in Algeria (BRN +5 mmbbl and other minor fields) and negative revisions (-13 mmbbl) mainly in Algeria (BRW -4 mmbbl) and other minor fields. In Egypt there were revisions of 11 mmbbl, consisting of positive revisions (21 mmbbl) mainly in Meleiha and negative revisions (-10 mmbbl) mainly in Belayim. In Sub-Saharan Africa, revisions totaled +21 mmbbl, consisting of positive revisions (+74 mmbbl) primarily in Nigeria (+42 mmbbl) and Angola (+22 mmbbl) and negative revisions (-53 mmbbl) including -23 mmbbl in Congo and -13 mmbbl in Nigeria. In Kazakhstan, revisions were negative 58 mmbbl, mainly related to the Karachaganak field. In the Rest of Asia revisions (-74 mmbbl) were due to positive revisions (+21 mmbbl) in the United Arab Emirates and negative revisions (-95 mmbbl) mainly in Iraq. In the Americas there were total revisions of 21 mmbbl, comprising positive revisions (+38 mmbbl) in the United States and negative revisions (-17 mmbbl) in Mexico.

In 2022, revisions of previous estimates were negative of 113 mmbbl. The main positive revisions were in the United Arab Emirates (+23 mmbbl) particularly of the Umm Shaif field (19 mmbbl), the United States (+16 mmbbl) mainly at the Triton and Allegheny fields, and Libya (15 mmbbl) at the Wafa and Structure E fields. The main negative changes were in Nigeria (-70 mmbbl), Iraq (-39 mmbbl) and Kazakhstan (-34 mmbbl) due to price effect and Algeria (-23 mmbbl).

In 2023 revisions of previous estimates are +160 mmbbl. The main positive revisions are: 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 are: Nigeria (-8 mmbbl) mainly on NAOC fields; in the United States of America (-10 mmbbl) mainly on Triton, Oooguruk and Allegheny fields.

Improved Recovery

In 2021, 12 mmbbl were totaled from recovery-assisted improvements primarily on the Oooguruk field in the U.S.

In 2022, 6 mmbbl were booked due to improved recovery mainly at the Mizton field in Mexico and the BRW field in Algeria.

In 2023 there were no increases due to improvements from assisted recovery.

Extensions and Discoveries

Table of Contents

In 2021, new discoveries and extensions total 23 million barrels, primarily related to Cuica and Ndungu in Block 15/06 and the New Gas Consortium project in Angola and the BKNEP, Zas and Ret projects in Algeria.

In 2022, 70 mmbbl of new discoveries and extensions are realized mainly due to the final investment decision on the development of the Baleine field in Ivory Coast (59 mmbbl), the NAHE project in Algeria, and the Talbot field in the United Kingdom.

In 2023, new discoveries and extensions amount to 50 mmbbl, mainly related to the United Arab Emirates following the final investment decision in the Hail and Ghasha project.

Sales of Minerals in Place

In 2021, there was a sale of OML 17 in Nigeria for 2 mmbbl.

In 2022, 170 mmbbl were de-booked in connection to the contribution of Eni's assets in Angola to the JV Azule set up 50% with bp and the sale of OML 11 in Nigeria.

In 2023, the divestment of 2 mmbbl mainly concerns the reduction of the share in the Ghasha concession in the United Arab Emirates.

Equity-accounted entities

Purchase of Minerals in Place

In 2021, no purchases of proved reserves were made.

In 2022, acquisitions amounted to 232 mmbbl due to the acquisition of a 50% stake in the JV Azule in Angola (132 mmbbl) and to Eni's joining the NFE project in Qatar (100 mmbbl).

In 2023 the 2 mmbbl of acquisition of a share in Block 3/05a in Azule.

Revisions of Previous Estimates

In 2021, revisions were negative 4 mmbbl, mainly located in the Rest of Europe (+17 mmbbl) in Norway and the Americas (-23 mmbbl in Venezuela). Minor revisions in Angola, Tunisia and Mozambique.

In 2022, revisions were a positive 97 mmbbl, located mainly in Azule in Angola (+38 mmbbl), Vår Energi in Norway (+37 mmbbl) and Venezuela (+21 mmbbl).

In 2023, positive revisions of +20 mmbbl are mainly due to Qatar (+10 mmbbl) on the NFE field, Vår Energi in Norway (+9 mmbbl).

Extensions and Discoveries

In 2021, extensions and new discoveries total 2 mmbbl and were located in Norway.

In 2022, extensions and new discoveries of 58 mmbbl were reported by Azule in Angola and Vår Energi in Norway.

No extensions or new discoveries are recorded in 2023.

Sales of Minerals in Place

Table of Contents

In 2020 and 2021, no sales of proved reserves were made.

In 2022, sales of 37 mmbbl related to the IPO of Vår Energi in Norway.

In 2023 sales amount to -1 mmbbl for the divestment of the Brage field in Vår Energi in Norway.

Proved reserves of natural gas

(billion cubic feet)

2023	Italy	Rest of Europe	North Africa	Egypt	Sub - Saharan Africa	Kazakhstan	Rest of Asia	America	Australia and Oceania	Total
Consolidated subsidiaries
Reserves at
December 31, 2022	869	223	2,323	3,881	2,341	1,560	1,281	264	408	13,150
of which: developed	695	214	670	2,732	1,306	1,560	796	195	223	8,391
undeveloped	174	9	1,653	1,149	1,035		485	69	185	4,759
Purchase of Minerals in Place			214							214
Revisions of Previous Estimates	67	(10)	832	(506)	294	79	112	5	(202)	671
Improved Recovery
Extensions and Discoveries				4	5		275			284
Production(a)	(77)	(39)	(335)	(478)	(161)	(93)	(187)	(25)	(14)	(1,409)
Sales of Minerals in Place							(178)	(113)		(291)
Reserves at December 31, 2023	859	174	3,034	2,901	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	3,048	2,901	3,980	1,546	2,709	1,391	192	17,315
Developed	653	526	933	2,262	2,386	1,546	725	1,367	58	10,456
consolidated subsidiaries	653	167	919	2,262	1,350	1,546	725	107	58	7,787
equity-accounted entities		359	14		1,036			1,260		2,669
Undeveloped	206	163	2,115	639	1,594		1,984	24	134	6,859
consolidated subsidiaries	206	7	2,115	639	1,129		578	24	134	4,832
equity-accounted entities		156			465		1,406			2,027

(a) It includes production volumes consumed in operations equal to 206 Bcf.

(b) It includes production volumes consumed in operations equal to 33 Bcf.

Table of Contents

(billion cubic feet)

					Sub -				Australia
		Rest of	North		Saharan		Rest of		and
2022	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	America	Oceania	Total
Consolidated subsidiaries
Reserves at December 31, 2021	918	247	2,272	4,152	2,953	1,705	1,522	274	428	14,471
of which: developed	729	242	781	3,656	1,759	1,705	971	210	266	10,319
undeveloped	189	5	1,491	496	1,194		551	64	162	4,152
Purchase of Minerals in Place			6					2		8
Revisions of Previous Estimates	39	15	280	193	(285)	(73)	(53)	17	(1)	132
Improved Recovery			1							1
Extensions and
Discoveries		7	37	52	154					250
Production(a)	(88)	(46)	(273)	(516)	(176)	(72)	(185)	(29)	(19)	(1,404)
Sales of Minerals in Place					(305)		(3)			(308)
Reserves at December 31, 2022	869	223	2,323	3,881	2,341	1,560	1,281	264	408	13,150
Equity-accounted entities
Reserves at
December 31, 2021		654	10		1,285			1,460		3,409
of which: developed		457	10		165			1,460		2,092
undeveloped		197			1,120					1,317
Purchase of Minerals in Place					194		1,490			1,684
Revisions of Previous Estimates		144			127			(10)		261
Improved Recovery
Extensions and Discoveries		19								19
Production(b)		(108)	(1)		(44)			(95)		(248)
Sales of Minerals in Place		(63)								(63)
Reserves at December 31, 2022		646	9		1,562		1,490	1,355		5,062
Reserves at December 31, 2022	869	869	2,332	3,881	3,903	1,560	2,771	1,619	408	18,212
Developed	695	658	679	2,732	2,376	1,560	796	1,550	223	11,269
consolidated subsidiaries equity-accounted	695	214	670	2,732	1,306	1,560	796	195	223	8,391
entities		444	9		1,070			1,355		2,878
Undeveloped	174	211	1,653	1,149	1,527		1,975	69	185	6,943
consolidated subsidiaries	174	9	1,653	1,149	1,035		485	69	185	4,759
equity-accounted entities		202			492		1,490			2,184

(a) It includes production volumes consumed in operations equal to 208 Bcf.

(b) It includes production volumes consumed in operations equal to 27 Bcf.

Table of Contents

		Rest of	North		Sub - Saharan		Rest of		Australia and
2021	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	America	Oceania	Total
Consolidated subsidiaries
Reserves at December 31, 2020	348	208	2,201	4,692	3,864	2,003	1,589	175	474	15,554
of which: developed	280	194	1,014	4,511	1,751	2,003	674	109	315	10,851
undeveloped	68	14	1,187	181	2,113		915	66	159	4,703
Purchase of Minerals in Place								1		1
Revisions of Previous Estimates	661	78	321	(2)	(903)	(213)	120	125	(15)	172
Improved Recovery
Extensions and Discoveries		5	13		186		2			206
Production(a)	(91)	(44)	(263)	(538)	(179)	(85)	(189)	(27)	(31)	(1,447)
Sales of Minerals in Place					(15)					(15)
Reserves at December 31, 2021	918	247	2,272	4,152	2,953	1,705	1,522	274	428	14,471
Equity-accounted entities
Reserves at
December 31, 2020		510	14		364			1,559		2,447
of which: developed		415	14		170			1,559		2,158
undeveloped Purchase of Minerals in Place		95			194					289
Revisions of Previous Estimates		234	(3)		952			(12)		1,171
Improved Recovery
Extensions and Discoveries		28								28
Production(b)		(118)	(1)		(31)			(87)		(237)
Sales of Minerals in Place
Reserves at December 31, 2021		654	10		1,285			1,460		3,409
Reserves at December 31, 2021	918	901	2,282	4,152	4,238	1,705	1,522	1,734	428	17,880
Developed	729	699	791	3,656	1,924	1,705	971	1,670	266	12,411
consolidated subsidiaries	729	242	781	3,656	1,759	1,705	971	210	266	10,319
equity-accounted entities		457	10		165			1,460		2,092
Undeveloped	189	202	1,491	496	2,314		551	64	162	5,469
consolidated subsidiaries	189	5	1,491	496	1,194		551	64	162	4,152
equity-accounted entities		197			1,120					1,317

(a) It includes production volumes consumed in operations equal to 208 Bcf.

(b) It includes production volumes consumed in operations equal to 15 Bcf.

Table of Contents

Main changes in proved reserves of natural gas reported in the tables above for the period 2021, 2022 and 2023 are discussed below.

Consolidated subsidiaries

Purchase of Minerals in Place

In 2021, 1 BCF of acquisition related to the Lucius field in the United States is recorded.

In 2022, acquisitions of 8 BCF cubic meters were made mainly for the acquisition of the BHP share in Algeria (6 BCF) and a share in some fields in the United States Gulf of Mexico.

In 2023 there is 214 BCF meters due to the acquisition of some BP assets in Algeria.

Revisions of Previous Estimates

In 2021, total revisions were 172 BCF as follows: Italy (661 BCF) mainly due to recovery of non-economic cutoffs; Rest of Europe (78 BCF) in the United Kingdom mainly due to recovery of non-economic cutoffs; Rest of North Africa (321 BCF) mainly in Libya due to price effect; Egypt (-2 BCF), consisting of positive revisions of 110 BCF meters mainly in Baltim SW and negative revisions 112 BCF mainly in Port Fouad; Sub-Saharan Africa total revisions of -903 BCF, primarily linked to the reclassification of the Mozambique project from a consolidated company to a equity-accounted company (-993 BCF) and positive revisions of 274 BCF, primarily in Nigeria. In Kazakhstan, reductions of 213 BCF were recorded mainly in Karachaganak due to the PSA effect; in the Rest of Asia, positive revisions of 120 BCF meters were mainly located in Indonesia (Merakes); in the Americas, revisions of 125 BCF occurred mainly in the United States due to the recovery of noneconomic cutoffs; in Australia and Oceania, revisions totaled -15 BCF mainly related to the Blacktip project.

In 2022, total revisions were 132 BCF. The main positive revisions were in Congo (469 BCF) mainly at the Nené field, Libya (357 BCF) and Egypt (193 BCF). The main negative revisions were in Nigeria (-764 BCF), Algeria (-74 BCF) and Kazakhstan (-73 BCF).

In 2023 total revisions are +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.

Improved Recovery

In 2021, no material improved recoveries were recorded.

In 2022, we had 1 BCF of improved recoveries in Algeria on the BRW and BKNE Alpha fields.

In 2023 there were no improvements from assisted recovery.

Extensions and Discoveries

In 2021, new discoveries and extensions totaled 206 BCF and related primarily to the New Gas Consortium project in Angola and to a lesser extent the Berkine North project in Algeria.

In 2022, new discoveries and extensions amounted to 250 BCF and mainly related to the final investment decision in Baleine in Ivory Coast and Bashrush in Egypt.

In 2023, new discoveries and extensions are 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.

Sales of Minerals in Place

Table of Contents

In 2021, there were divestments of 15 BCF related to the exit from OML 17 in Nigeria.

In 2022, sales were 308 BCF in relation to the contribution of Eni's assets in Angola to the JV Azule and 3 BFC related to Pakistan.

In 2023 divestments of 291 BCF are 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.

Equity-accounted entities

Purchase of Minerals in Place

No purchase was made in 2021.

In 2022, we had acquisitions for 1,684 BCF due to Eni's entry into the NFE project in Qatar and the acquisition of a 50% stake in the JV Azule in Angola.

No purchase was made in 2023.

Revisions of Previous Estimates

In 2021, revisions to previous estimates were 1,171 BCF, primarily due to the reclassification of the Mozambique project from a consolidated company to an equity-accounted company.

In 2022, revisions of previous estimates are 261 BCF, mainly due to Azule in Angola, Vår Energi in Norway, and Coral in Mozambique.

In 2023, revisions of previous estimates are -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.

Extensions and Discoveries

In 2021, 28 BCF of extensions and new discoveries were recorded, mainly due to the investment decision in Tommeliten Alpha in Norway.

In 2022, extensions and new discoveries were 19 BCF due to Vår Energi in Norway.

In 2023, there were no extensions or new relevant discoveries.

Sales of Minerals in Place

Table of Contents

In 2021, no sales were made.

In 2022, sales of 63 BCF were due to the IPO of Vår Energi in Norway.

In 2023 divestments are 2 BCF in the Brage field in Vår Energi in Norway.

Standardized measure of discounted future net cash flows

Estimated future cash inflows represent the revenues that would be received from production and are 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 expenditures 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.

Table of Contents

The standardized measure of discounted future net cash flows by geographical area consists of the following:

(€ million)

					Sub -				Australia
		Rest of	North		Saharan		Rest		and
December 31, 2023	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated
subsidiaries
Future cash inflows	22,724	3,926	49,789	23,046	35,147	40,081	40,622	14,951	707	230,993
Future production costs	(8,848)	(1,227)	(8,361)	(7,078)	(13,512)	(6,475 )	(11,042)	(5,852)	(164)	(62,559)
Future development and
abandonment costs	(4,270)	(824)	(6,664)	(2,719)	(7,757)	(1,814 )	(7,437)	(1,954)	(355)	(33,794)
Future net inflow
before income tax	9,606	1,875	34,764	13,249	13,878	31,792	22,143	7,145	188	134,640
Future income tax	(2,233)	(1,274)	(19,528)	(4,541)	(4,729)		(8,186 ) (16,348)	(3,161)	(8)	(60,008)
Future net cash flows	7,373	601	15,236	8,708	9,149	23,606	5,795	3,984	180	74,632
10 % discount factor	(3,325)	(39)	(7,541)	(2,926)	(4,223)	(11,668 )	(3,081)	(1,462)	(58)	(34,323)
Standardized measure
of discounted future
net cash flows	4,048	562	7,695	5,782	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	7,713	5,782	10,944	11,938	3,672	4,437	122	52,594

Table of Contents

					Sub -				Australia
		Rest of	North		Saharan		Rest		and
December 31, 2022	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Future cash inflows	38,968	7,609	50,838	34,198	48,292	53,529	45,179	21,233	1,525	301,371
Future production costs	(10,267)	(1,752)	(6,675)	(11,171)	(15,823)	(7,844)	(12,181)	(5,950)	(230)	(71,893)
Future development and abandonment costs	(4,484)	(1,296)	(4,894)	(2,941)	(10,057)	(1,873)	(4,562)	(3,063)	(377)	(33,547)
Future net inflow
before income tax	24,217	4,561	39,269	20,086	22,412	43,812	28,436	12,220	918	195,931
Future income tax	(6,388)	(3,087)	(23,766)	(7,119)	(7,990)	(11,568)	(21,227)	(4,903)	(81)	(86,129)
Future net cash flows	17,829	1,474	15,503	12,967	14,422	32,244	7,209	7,317	837	109,802
10 % discount factor	(7,141)	(344)	(7,176)	(4,562)	(6,456)	(16,087)	(2,980)	(3,443)	(357)	(48,546)
Standardized measure of discounted future net
cash flows	10,688	1,130	8,327	8,405	7,966	16,157	4,229	3,874	480	61,256
Equity-accounted entities
Future cash inflows		50,468	265		42,450		33,075	8,133		134,391
Future production costs		(7,628)	(123)		(10,579)		(9,749)	(2,083)		(30,162)
Future development and abandonment costs		(6,458)	(57)		(3,508)		(560)	(178)		(10,761)
Future net inflow
before income tax		36,382	85		28,363		22,766	5,872		93,468
Future income tax		(27,333)	(3)		(8,117)		(19,393)	(2,469)		(57,315)
Future net cash flows		9,049	82		20,246		3,373	3,403		36,153
10 % discount factor		(2,501)	(15)		(9,058)		(2,462)	(1,416)		(15,452)
Standardized measure of discounted future net cash flows		6,548	67		11,188		911	1,987		20,701
Total consolidated subsidiaries and equity-accounted entities	10,688	7,678	8,394	8,405	19,154	16,157	5,140	5,861	480	81,957
					F-211

Table of Contents

		Rest of	North		Sub - Saharan		Rest		Australia and
December 31, 2021	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
Consolidated subsidiaries
Future cash inflows	18,933	4,679	33,142	31,344	40,929	36,430	32,594	13,607	1,511	213,169
Future production costs	(6,929)	(1,496)	(6,325)	(9,726)	(13,196)	(7,343)	(9,578)	(4,189)	(251)	(59,033)
Future development and
abandonment costs	(4,104)	(865)	(4,688)	(2,036)	(5,117)	(1,750)	(4,278)	(2,298)	(288)	(25,424)
Future net inflow
before income tax	7,900	2,318	22,129	19,582	22,616	27,337	18,738	7,120	972	128,712
Future income tax	(2,037)	(1,001)	(12,345)	(6,736)	(8,372)	(6,301)	(12,899)	(2,386)	(75)	(52,152)
Future net cash flows	5,863	1,317	9,784	12,846	14,244	21,036	5,839	4,734	897	76,560
10 % discount factor	(2,112)	(170)	(4,516)	(4,211)	(5,608)	(10,703)	(2,295)	(1,980)	(350)	(31,945)
Standardized measure of discounted future net
cash flows	3,751	1,147	5,268	8,635	8,636	10,333	3,544	2,754	547	44,615
Equity-accounted entities
Future cash inflows		28,037	230		8,884			5,971		43,122
Future production costs		(8,316)	(120)		(1,590)			(1,454)		(11,480)
Future development and abandonment costs		(6,566)	(85)		(95)			(77)		(6,823)
Future net inflow before income tax		13,155	25		7,199			4,440		24,819
Future income tax		(8,591)	(9)		(1,286)			(1,309)		(11,195)
Future net cash flows		4,564	16		5,913			3,131		13,624
10 % discount factor		(1,462)	16		(3,498)			(1,399)		(6,343)
Standardized measure of discounted future net cash flows		3,102	32		2,415			1,732		7,281
Total consolidated subsidiaries and equity-accounted entities	3,751	4,249	5,300	8,635	11,051	10,333	3,544	4,486	547	51,896
					F-212

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, 2023, 2022 and 2021, are as follows:

(€ million)

	Consolidated	Equity accounted
2023	subsidiaries	entities	Total
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

(€ million)

2022	Consolidated subsidiaries	Equity accounted entities	Total
Standardized measure of discounted future net cash flows at December 31, 2021	44,615	7,281	51,896
Increase (Decrease):
- sales, net of production costs	(25,987)	(4,912)	(30,899)
- net changes in sales and transfer prices, net of production costs	56,002	24,343	80,345
- extensions, discoveries and improved recovery, net of future production and development
costs	1,519	2,139	3,658
- changes in estimated future development and abandonment costs	(7,046)	(3,169)	(10,215)
- development costs incurred during the period that reduced future development costs	3,821	2,000	5,821
- revisions of quantity estimates	(1,295)	7,134	5,839
- accretion of discount	7,226	1,510	8,736
- net change in income taxes	(18,393)	(21,676)	(40,069)
- purchase of reserves in-place	765	10,200	10,965
- sale of reserves in-place	(6,436)		(6,436)
- changes in production rates (timing) and other	6,465	(4,149)	2,316
Net increase (decrease)	16,641	13,420	30,061
Standardized measure of discounted future net cash flows at December 31, 2022	61,256	20,701	81,957

2021	Consolidated subsidiaries	Equity accounted entities	Total
Standardized measure of discounted future net cash flows at December 31, 2020	24,386	3,306	27,692
Increase (Decrease):
- sales, net of production costs	(16,402)	(3,381)	(19,783)
- net changes in sales and transfer prices, net of production costs	40,864	9,256	50,120
- extensions, discoveries and improved recovery, net of future production and development
costs	1,304	142	1,446
- changes in estimated future development and abandonment costs	(2,737)	(734)	(3,471)
- development costs incurred during the period that reduced future development costs	2,877	1,385	4,262
- revisions of quantity estimates	1,963	1,665	3,628
- accretion of discount	3,810	514	4,324
- net change in income taxes	(14,022)	(5,216)	(19,238)
- purchase of reserves in-place	27		27
- sale of reserves in-place	(28)		(28)
- changes in production rates (timing) and other	2,573	344	2,917
Net increase (decrease)	20,229	3,975	24,204
Standardized measure of discounted future net cash flows at December 31, 2021	44,615	7,281	51,896

F-214

Table of Contents

EXHIBIT 1

The English text is a translation of the Italian official "By-laws of Eni S.p.A.". For any conflict or discrepancies between the two texts the Italian text shall prevail.

Part I- Formation - Name – Registered Office and Duration of the Company

ARTICLE 1

1.1 Eni SpA, formed as a result of the transformation of Ente Nazionale Idrocarburi, a public agency, pursuant to Law No. 136 of February 10, 1953, is governed by these By- laws.

1.2 The first letter of the Company's name may be written in either upper or lower case.

ARTICLE 2

2.1 The Company's registered office is located in Rome, and it has two branch offices in San Donato Milanese (Milan).

2.2 The Company may establish and/or close offices, representative offices, affiliates and branch offices either in Italy or abroad, in the manner provided for by law.

ARTICLE 3

3.1 The duration of the Company shall expire on December 31, 2100. Its duration may be extended one or more times by resolution of the Shareholders' Meeting.

Part II – Corporate Purpose

ARTICLE 4

4.1 The corporate purpose is the direct and/or indirect exercise, through equity holdings in companies or other entities of activities in the field of hydrocarbons and natural gases, such as exploration and development of hydrocarbon fields, the construction and operation of pipelines for transporting the same, the processing, transformation, storage, use and sale of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law.

The corporate purpose also includes the direct and/or indirect exercise, through equity holdings in companies or other enterprises, of activities in the fields of chemicals, nuclear fuels, geothermal energy, other 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 the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities.

The corporate purpose also comprises performing and managing the technical and financial coordination of subsidiaries and associated companies and providing financial assistance to them.

The Company may undertake any transactions necessary or useful for the achievement of the corporate purpose; by way of example, it may undertake transactions involving real estate or moveable assets, commercial and industrial transactions, financial and banking transactions of any sort, and any other act that is in any way connected with the corporate purpose with the exception of fundraising on a public basis and the performance of investment services as defined by Legislative Decree No. 58 of February 24, 1998.

The Company may, finally, 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.

3

Part III – Share capital - Shares – Bonds

ARTICLE 5

5.1 The Company's share capital is equal to €4,005,358,876.00 (four billion five million three hundred and fifty-eight thousand eight hundred and seventy-six), represented by 3,375,937,893 (three billion three hundred and seventy-five million nine hundred and thirty-seven thousand eight hundred and ninety-three) ordinary shares without indication of par value.

5.2 Shares may not be split and each share gives entitlement to one vote.

5.3 The status of shareholder in itself constitutes approval of these By-laws.

5.4 The Extraordinary Shareholders' Meeting of May 10, 2023 authorised the cancellation of a maximum of 275,000,000 Eni treasury shares purchased in execution of the Plan approved by the Shareholders' Meeting of May 10, 2023, conferring delegated powers on the Board of Directors – with the option of delegation to the Chief Executive Officer and sub-delegation by the same – to perform this cancellation, with several actions or at one time, by July 2024, to change, as a consequence, the number of shares indicated in paragraph 1 of this article, reducing it by a number of shares equal to those effectively cancelled and to proceed, after completing the cancellation, to annul this paragraph.

ARTICLE 6

6.1 Pursuant to Article 3 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994, no shareholder may hold, in any capacity, more than 3% of the Company's share capital.

The calculation of such maximum shareholding limit also takes account of the aggregate shareholding held by the controlling party, whether a natural or legal person or company; subsidiaries under direct or indirect control, as well as entities controlled by the same controlling party; linked entities and persons related to the second degree by blood or marriage, with the exception of legally separated spouses.

A relationship of control, including with reference to entities other than companies, exists in the cases envisaged by Article 2359, paragraphs 1 and 2 of the Italian Civil Code.

A link exists in the case set forth in Article 2359, paragraph 3, of the Italian Civil Code as well as between entities that directly or indirectly, by way of subsidiaries other than those managing investment funds, participate, even with third parties, in agreements regarding the exercise of voting rights or the transfer of shares or other equity holdings in third-party companies or, in any event, in agreements as referred to in Article 122 of Legislative Decree No. 58 of February 24, 1998 regarding thirdparty companies if said agreements involve least 10% of voting share capital if they are listed companies or 20% if they are unlisted companies.

The calculation of the aforementioned shareholding limit (3%) also takes account of shares held by any fiduciary and/or nominee.

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. If the voting rights of shares exceeding this limit are exercised, any shareholders' resolution adopted pursuant to such a vote may be challenged pursuant to Article 2377 of the Italian Civil Code if the required majority would not have been reached without the votes exceeding the aforementioned maximum limit.

Shares for which voting rights may not be exercised shall nevertheless be included in the determination of the quorum at Shareholders' Meetings.

7.1 When shares are fully paid up, and if the law so allows, they may be issued to bearer. Bearer shares may be converted into registered shares and vice-versa. Conversion operations shall be carried out at the shareholder's expense.

ARTICLE 8

8.1 If for whatever reason a share should belong to more than one person, the rights attaching to said share may be exercised by only one person or by a proxy acting for all co-holders.

ARTICLE 9

9.1 The Shareholders' Meeting may resolve to increase the Company share capital and set the terms, conditions and means thereof.

9.2 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 pursuant to Article 2349 of the Italian Civil Code.

ARTICLE 10

10.1 Payments in respect of shares may be called by the Board of Directors in one or more installments.

10.2 Shareholders who are late in payment shall be charged interest calculated at the official discount rate established by the Bank of Italy, without prejudice to the provisions of Article 2344 of the Italian Civil Code.

ARTICLE 11

11.1 The Company may issue bonds, including convertible bonds and warrants, in compliance with the provisions of law.

Part IV – Shareholders' Meetings

ARTICLE 12

12.1 Ordinary and extraordinary 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.

12.2 The ordinary Shareholders' Meeting shall be called at least once a year, within 180 days of the end of the Company's financial year, to approve the financial statements, since the Company is required to draw up consolidated financial statements.

12.3 The directors shall call a Shareholders' Meeting without delay when shareholders representing at least one twentieth of the share capital so request. Shareholders' Meetings may not be called upon the request of the shareholders for matters upon which, according to law, the Shareholders' Meeting must resolve upon a proposal of the directors or on the basis of a project or report of the directors themselves. The shareholders who request a meeting to be convened shall prepare a report on the proposals relating to the matters to be discussed. The Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the Company's registered office, on the Company's website and in any other manner established in Consob regulations at the time the notice calling the meeting is published.

12.4 The Board of Directors shall make a report on each of the items on the agenda available to the public as provided for in the previous paragraph by the deadlines for publication of the notice calling the Shareholders' Meeting for each of the items on the agenda.

13.1 The Shareholders' Meeting shall be called by way of a notice published on the Company's website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law.

Shareholders who severally or jointly represent at least one fortieth of the Company's share capital may ask for items to be added to the agenda by submitting a request within ten days of publication of the notice calling the meeting, unless a different term is provided for by law, specifying the additional proposed items in their request or presenting proposed resolutions on items already on the agenda. Requests, together with the certificate attesting ownership of the shares, are submitted in writing, by mail or electronically in the manners provided for in the notice calling the meeting. These proposed resolutions may be presented individually at the Shareholders' Meeting by persons entitled to vote. Matters upon which, according to law, the Shareholders' Meeting mustresolve upon a proposal of theBoard of Directors or on the basis of a project or report of the directors other than the report on the items in the agenda, may not be added to the agenda. The Board of Directors shall give notice of the additions to the agenda or the proposed resolutions approved in the same manner prescribed for the publication of the notice calling the meeting at least fifteen days before the date set for the Shareholders' Meeting, unless a different term is required by law. The proposed resolutions on items already on the agenda are made available to the public as prescribed by Article 12.3 of these By-laws, simultaneous with publication of the announcement of their presentation. The requesting or proposing shareholders shall send, by the final deadline for the submission of requests for additions to the agenda or of proposed resolutions, a report to theBoard of Directors, explaining the reasons for the addition or the proposed resolution. TheBoard of Directorsshall make the report available to the public, together with its own evaluations, if any, at the same time as the publication of the notice of the additions to the agenda or of the presentation of proposed resolutions in the manner set out in Article 12.3 of these By-laws.

13.2 Entitlement 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 or debit records entered on the 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 this Article, 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.

6

14.1 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 laws. Electronic notification of the proxy may be made through a special section of the Company's 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 collecting proxies shall be made available to said associations in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.

14.2 The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.

14.3 The right to vote may also be exercised by correspondence in accordance with the applicable provisions of law and regulations. If envisaged 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 law, applicable regulations and the Shareholders' Meeting Rules.

14.4 The Shareholders' Meetings are governed by the Shareholders' Meeting Rules as approved with a resolution of the ordinary Shareholders' Meeting.

14.5 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 law 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.

ARTICLE 15

15.1 The Shareholders' Meeting is chaired by the Chairman of the Board of Directors, or in the event of the Chairman's absence or impediment, by the Chief Executive Officer; in their absence, the Shareholders' Meeting shall elect its own Chairman.

15.2 The Chairman of the meeting is assisted by a Secretary, who need not be a shareholder, to be designated by the participants in the meeting, and may appoint one or more scrutineers.

ARTICLE 16

16.1 The ordinary Shareholders' Meeting decides on all matters for which it is legally responsible and authorizes the transfer of the business.

16.2 The ordinary and extraordinary Shareholders' Meetings, are normally held on single call; in such case the majorities required by law shall apply. 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 in first, second or third call must be passed with the majorities required by law in each case.

16.3 The resolutions of the Shareholders' Meeting, approved in accordance with the law and these By-laws, shall be binding on all shareholders, including those dissenting or not present.

16.4 The minutes of ordinary meetings shall be signed by the Chairman and the Secretary.

16.5 The minutes of extraordinary meetings shall be drawn up by a notary public.

7

Part V – The Board of Directors

ARTICLE 17

17.1 The Company is governed by a Board of Directors consisting of no fewer than three and no more than nine members. The Shareholders' Meeting shall determine the number within these limits.

17.2 The directors shall be appointed for a period of up to three financial years; this term shall lapse on the date of the Shareholders' Meeting convened to approve the financial statements for their last year in office. They may be re-elected.

17.3 The Board of Directors shall be elected by the Shareholders' Meeting on the basis of slates presented by shareholders and by the Board of Directors. The candidates shall be listed on the slates in numerical order.

The slates shall be filed with the Company's registered office, including remotely in the manner indicated in the notice calling the meeting, by the twenty- fifth day before the date of the Shareholders' Meeting at first or single call convened to appoint the members of the Board of Directors. They shall be made available to the public as provided for by law and Consob regulations at least twenty-one days before the date set for the Shareholders' Meeting at first or single call. Each shareholder may, severally or jointly, submit and vote on a single slate only. Controlling persons, subsidiaries and companies under common control may not submit or participate in the submission of other slates, nor can they vote on them, either directly or through nominees or trustees. As used herein, subsidiaries are those companies referred to in Article 93 of Legislative Decree No. 58 of February 24, 1998. Each candidate may stand on a single slate, on penalty of disqualification. Only those shareholders who, severally or jointly, represent at least 1% of share capital or any other threshold established by Consob regulations shall be entitled to submit a slate. Ownership of the minimum holding needed to submit slates shall be determined with regard to the shares registered to the shareholder on the day on which the slates are filed with the Company. Related certification may be submitted after the filing, provided that submission takes place by the deadline set for the publication of the slates by the Company.

At least one director, if there are no more than five directors, or at least three directors, if there are more than five, shall satisfy the independence requirements established for the members of the board of statutory auditors of listed companies.

The candidates meeting such independence requirements shall be expressly identified in each slate.

All candidates shall also satisfy the integrity requirements established by applicable law. Pursuant to applicable genderbalance legislation, at least two fifths of the Board shall consist of directors belonging to the less-represented gender, rounded up, unless the number of members of the Board is equal to three, in which case this number is rounded down.

Slates that contain three or more candidates shall include candidates of both genders. The slates competing to appoint the majority of the members of the Board of Directors, made up of more than three candidates, must reserve two fifths to the positions on the slate to the less-represented gender, rounded up.

Together with the filing of each slate, on penalty of inadmissibility, the following shall also be filed: the curriculum vitae of each candidate, statements of each candidate accepting his/her nomination and affirming, under his/her personal responsibility, the absence of any grounds making him/her ineligible or incompatible for such position and that he/she satisfies the aforementioned requirements of integrity and independence (where applicable).

The appointed 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.

The Board of Directors shall periodically evaluate the independence and integrity of its members and whether cause for ineligibility or incompatibility has arisen. If the integrity or independence requirements established by applicable legislation should no longer be met by a director or if cause for ineligibility or incompatibility should have arisen, the Board of Directors shall declare the director disqualified and replace him/her or shall invite him/her to rectify the situation of incompatibility by a deadline set by the Board itself, on penalty of disqualification.

Directors shall be elected in the following manner:

a) seven-tenths of the directors to be elected shall be drawn from the slate that receives the most votes of the shareholders in the order in which they appear on the slate, rounded off in the event of a decimal number to the next lowest whole number;

b) the remaining directors shall be drawn from the other slates. Said slates shall not be connected in any way, directly or indirectly, to the shareholders who have submitted or voted the slate that receives the largest number of votes. For this purpose, the votes received by each slate shall be divided by one or two or three depending upon the number of directors to be elected. The quotients, or points, thus obtained shall be assigned progressively to candidates of each slate in the order given in the slates themselves. The candidates of all the slates shall be ranked by the points assigned in single list in descending order. Those who receive the most points shall be elected. In the event that more than one candidate receives the same number of points, the candidate elected shall be the person from the slate that has not hitherto had a director elected or that has elected the least number of directors. In the event that none of the slates has yet had a director elected or that all of them have had the same number of directors elected, the candidate among all such slates who has received the highest number of votes shall be elected. In the event of equal slate votes and equal points, the entire Shareholders' Meeting shall vote again and the candidate elected shall be the person who receives a simple majority of the votes;

c) if the minimum number of independent directors required under these By-laws has not been elected following the above procedure, the points to be assigned to the candidates draw from the slates shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidates who do not meet the requirements of independence with the fewest points from among the candidates drawn from all of the slates shall be replaced, starting from the last, by the independent candidates, from the same slate as the replaced candidate (following the order in which they are listed), otherwise by persons meeting the independence requirements appointed in accordance with the procedure set out in letter d). In cases where candidates from different lists have received the same number of points, the candidate from the slate from which the largest number of directors has been drawn or, subordinately, the candidate drawn from the slate receiving the lowest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders' Meeting in a run-off election, shall be replaced;

c-bis) if the application of the procedure set out in letters a) and b) does not permit compliance with the gender-balance rules, the points to attribute to each candidate drawn from the slate shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidate of the over-represented gender with the fewest points from among the candidates drawn from all of the slates shall be replaced, without prejudice to the compliance with the required minimum number of independent directors, by the member of the less-represented gender who may be listed (with the next highest ordinal number) on the same slate as the candidate to be replaced, otherwise by a person to be appointed following the procedure set out in letter d). In cases where candidates from different lists have received the same minimum number of points, the candidate from the slate from which the largest number of directors has been drawn or, subordinately, the candidate drawn from the slate receiving the fewest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders' Meeting in a run-off election, shall be replaced;

9

d) to appoint directors who for any reason were not appointed pursuant to the above procedures, the Shareholders' Meeting shall resolve, with the majorities required by law, to ensure that the composition of the Board of Directors complies with applicable law and the By-laws.

The slate voting procedure shall apply only to the election of the entire Board of Directors.

17.4 The Shareholders' Meeting may, during the Board's term of office, change the number of members of the Board of Directors, within the limits established in the first paragraph of this Article, and make the related appointments. The terms of directors so elected shall expire at the same time as those of the directors already in office.

17.5 If, during the year, the office of one or more directors should be vacated, he/she shall be replaced in accordance with Article 2386 of the Italian Civil Code. In any case, compliance with the required minimum number of independent directors and the applicable rules concerning gender balance shall not be affected.If a majority of the directors should vacate their offices, the entire Board shall be considered to have resigned, and the Board shall promptly call a Shareholders' Meeting to elect a new Board.

17.6 The Board may establish internal committees to provide advice and proposals on specific issues.

ARTICLE 18

18.1 If the Shareholders' Meeting has not appointed a Chairman, the Board shall elect one from among its members.

18.2 The Board, acting upon a proposal of the Chairman, shall appoint a Secretary, who need not be affiliated with the Company.

ARTICLE 19

19.1 The Board shall meet in the place indicated in the meeting notice whenever the Chairman or, in the event of his absence or impediment, the Chief Executive Officer deems necessary, or when a written request has been made by the majority of its members. The Board of Directors may also be convened pursuant to Article 28.4 of these By-laws. The meetings of the Board of Directors may be held by video or teleconference on the condition that all of the participants in the meeting can be identified and that all can follow and participate in real time in the discussion of the matters being addressed. The meeting shall be considered duly held in the place where the Chairman and the Secretary are present.

19.2 Notice shall normally be given at least five days in advance of the meeting. In urgent circumstances, the period of notice may be shorter. The Board of Directors shall decide how its meetings are to be convened.

19.3 The Board of Directors shall also be convened when so requested by at least two directors or by one director if the Board consists of three directors, to decide on a specific matter deemed to be of particular importance regarding the management of the Company. Said matter shall be specified in the request.

¹⁰

20.1 The Chairman of the Board or, in his absence, the eldest director in attendance shall chair the meeting.

ARTICLE 21

21.1 For a Board meeting to be valid, a majority of serving directors must be present.

21.2 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.

ARTICLE 22

22.1 The resolutions of the Board of Directors shall be registered in the minutes, which shall be recorded in a book kept for that purpose pursuant to the provisions of law, and said minutes shall signed by the Chairman of the meeting and by the Secretary.

22.2 Copies of the minutes shall be considered bona fide if they are signed by the Chairman or the person acting in place of the Chairman and countersigned by the Secretary.

ARTICLE 23

23.1 The Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, 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 these By- laws reserve to the Shareholders' Meeting.

23.2 The Board of Directors shall decide the following matters:

• the merger and proportional demerger of companies in which the Company owns shares or other equity holdings representing at least 90% of the share capital;

• the establishment and closing of branches;

• the amendment of the By-laws to comply with the provisions of law.

23.4 The Board of Directors and the Chief Executive Officer shall promptly report to the Board of Statutory Auditors at least every three months and in any event at the time of the meetings of the Board of Directors, on the activity carried out and on the transactions with the most significant impact on performance and the financial position carried out by the Company and its subsidiaries. In particular they shall report to the Board of Statutory Auditors those transactions in which they have an interest, either on their own behalf or on behalf of third parties.

11

24.1 The Board of Directors may delegate its powers to one of its members, within the limits set forth in Article 2381 of the Italian Civil Code. The Board may, in addition, delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may revoke delegated powers at any time, 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. The Chairman and the Chief Executive Officer, within the limits of the authority attributed to them, may delegate and empower Company employees or third parties to represent the Company for individual acts or specific categories of acts.

Further, acting upon proposal of the Chief Executive Officer and in agreement with the Chairman, the Board of Directors may also appoint one or more General Managers (Chief Operating Officers) and determine the powers to be conferred on them, once it has been ascertained that they fulfill the integrity requirements set by law. The Board of Directors shall periodically check the continuing compliance with integrity requirements of the General Managers (Chief Operating Officers). Failure to satisfy these requirements shall result in disqualification from the position.

Acting upon a proposal of the Chief Executive Officer, in agreement with the Chairman and with the approval of the Board of Statutory Auditors, the Board of Directors shall appoint the Officer responsible for preparing financial reporting documents.

The Officer responsible for preparing financial reporting documents shall be selected from among those persons who, for at least three years, have performed:

a) administration, control or management activities in companies listed on regulated stock exchanges in Italy or other European Union countries or other OECD countries with a share capital of no less than €2 million; or

• b) statutory audit activities in companies indicated in letter a) above; or
• c) professional activities or university teaching activities in the financial or accounting sectors; or
• d) management functions in public or private entities with financial, accounting or control expertise.

The Board of Directors shall ensure that the Officer responsible for preparing the financial reporting documents has adequate powers and means to perform the duties of the position and that administrative and accounting procedures are being followed.

ARTICLE 25

25.1 The Chairman and the Chief Executive Officer are severally vested with powers of legal representation of the Company before any judicial or administrative authority and with respect to third parties and exercise signature powers on behalf of the Company.

26.1 The Chairman and the members of the Board of Directors shall be entitled to compensation to be determined by the ordinary Shareholders' Meeting. Said resolution, once taken, shall remain valid for subsequent financial years until the Shareholders' Meeting should decide otherwise.

ARTICLE 27

27.1 The Chairman:

• a) represents the Company pursuant to Article 25.1;
• b) chairs the Shareholders' Meeting pursuant to Article 15.1;
• c) calls and chairs meetings of the Board of Directors pursuant to Articles 19.1 and 20.1;
• d) verifies that Board resolutions are implemented;
• e) exercises the powers delegated to him by the Board of Directors pursuant to Article 24.1.

Part VI – The Board of Statutory Auditors

ARTICLE 28

28.1 The Board of Statutory Auditors shall consist of five standing members and two alternate members, chosen from among persons who satisfy the professional and integrity requirements established by the Ministry of Justice Decree No. 162 of March 30, 2000.

Pursuant to the aforementioned decree, the fields closely connected with the business of the Company are: commercial law, business economics and corporate finance.

Similarly, the sectors closely connected with the business of the Company are engineering and geology.

The Statutory Auditors may be appointed as members of the administrative and control bodies of other companies within the limits set by Consob regulations.

28.2 The Board of Statutory Auditors shall be appointed by the Shareholders' Meeting on the basis of slates presented by shareholders. The candidates shall be listed on the slates in numerical order in a number no greater than the number of members of the body to be appointed.

The procedures set out in Article 17.3 and the provisions issued in Consob regulations shall apply to the submission, filing and publication of candidate slates.

Pursuant to applicable gender-balance legislation, two standing Statutory Auditors shall belong to the less represented gender.

Slates shall be divided into two sections: the first containing candidates for appointment as standing Statutory Auditors and the second containing candidates for appointment as alternate Statutory Auditors. At least the first candidate in each section must be entered in the register of auditors and have carried out statutory audit activities for no less than three years.

Slates that, considering both sections together, contain three or more candidates shall include, in the section for standing Statutory Auditors, candidates of both genders, as specified in the notice calling the Shareholders' Meeting, in order to comply with the applicable gender-balance legislation. If the section for alternate Statutory Auditors on these slates contains two candidates, they must be of different genders.

Three standing Statutory Auditors and one alternate Statutory Auditor shall be drawn from the slate that receives the majority of votes. The other two standing Statutory Auditors and the other alternate Statutory Auditor shall be appointed using the procedures set out in Article 17.3, letter b) of the By-laws. Said procedures shall be applied separately to each section of the other slates.

The Shareholders' Meeting shall appoint the Chairman of the Board of Statutory Auditors from among the standing Statutory Auditors appointed in accordance with Article 17.3 letter b) of these By-laws.

Where the application of the procedure set out above does not permit compliance with the gender-balance rules for standing Statutory Auditors, the points to attribute to each candidate drawn from the standing Statutory Auditor sections of the various slates shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidate of the over-represented gender with the fewest points from among the candidates drawn from all of the slates shall be replaced by the member of the less-represented gender who may be listed (with the next highest ordinal number) in the standing Statutory Auditor section on the same slate as the candidate to be replaced or, subordinately, in the alternate Statutory Auditor section of the same slate as the candidate to be replaced (in such case, the latter shall take the position of the alternate candidate that replaces him/her). If this does not permit compliance with the gender-balance rules, he/she shall be replaced by a person chosen by the Shareholders' Meeting with the majority required by law, so as to ensure that the membership of the Board of Statutory Auditors complies with the law and the By- laws. In cases where candidatesfrom different lists have received the same number of points, the candidate from the slate from which the largest number of Statutory Auditors has been drawn or, subordinately, the candidate drawn from the slate receiving the fewest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders' Meeting in a run-off election, shall be replaced.

For the appointment of Statutory Auditors who, for any reason, are not appointed using the above procedures, the Shareholders' Meeting shall resolve, with the majorities required by law, in such a manner as to ensure that the membership of the Board of Statutory Auditors complies with the law and the By-laws.

The slate voting procedure shall apply only in case of appointment of the entire Board of Statutory Auditors.

Should a standing Statutory Auditor from the slate that received a majority of the votes be replaced, the replacement shall be the alternate Statutory Auditor from the same slate; should a standing Statutory Auditor from other slates be replaced, the replacement shall be the alternate Statutory Auditor from those other slates. If the replacement results in non-compliance with gender-balance rules, the Shareholders' Meeting shall be called as soon as possible to approve the necessary resolutions to ensure compliance.

28.3 Statutory Auditors may be re-elected.

28.4 Subject to prior notification of the Chairman of the Board of Directors, the Board of Statutory Auditors may call Shareholders' Meetings and meetings of the Board of Directors. The power to call a meeting of the Board of Directors may be exercised individually by each member of the Board of Statutory Auditors; at least two Statutory Auditors are required to call Shareholders' Meetings.

The meetings of the Board of Statutory Auditors may be held by video or teleconference on the condition that all of the participants in the meetings can be identified and that all can follow and participate in real time in the discussion of the matters being addressed. The meeting shall be considered duly held in the place where the Chairman and the Secretary are present.

Part VII – Financial Statements and Profits

ARTICLE 29

29.1 The Company's financial year ends on December 31 of each year.

29.2 At the end of each financial year, the Board of Directors shall prepare the Company financial statements in compliance with the provisions of law.

29.3 The Board of Directors may distribute interim dividends to the shareholders during the financial year.

ARTICLE 30

30.1 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.

Part VIII - Winding Up and Liquidation of the Company

ARTICLE 31

31.1 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.

Part IX – General Provisions

ARTICLE 32

32.1 For all matters not expressly governed by these By-laws, the Italian Civil Code and applicable special laws shall apply.

32.2 Pursuant to Article 3, paragraph 2, of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994, Article 6.1, sixth paragraph, of these By-laws shall not apply to the shareholdings owned by the Ministry of the Economy and Finance, public entities or entitiesthey control.

ARTICLE 33

33.1 The Company retains all legal relationships in respect of assets and liabilities held by the public agency Ente Nazionale Idrocarburi before its transformation.

ARTICLE 34

34.1 The provisions of Articles 17.3, 17.5 and 28.2 directed to ensure compliance with applicable gender-balance legislation shall apply to the first election after 1 January 2020, for the number of consecutive terms of the Board of Directors and Board of Statutory Auditors as provided for by the law.

$$16$$

Eni SpA Registered Office Piazzale Enrico Mattei, 1 00144 Rome, Italy Branches 20097 San Donato Milanese, Milan Via Emilia, 1, 20097 San Donato Milanese, Milan Piazza E. Vanoni, 1, Company share capital €4,005,358,876 fully paid Rome Company Register Tax identification number 00484960588

DESCRIPTION OF SECURITIES REGISTERED UNDER SECTION 12 OF THE EXCHANGE ACT

A s of December 31, 2022, Eni SpA ("Eni", the "Company", "we", "us" and "our") had the following series of securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 (the "Exchange Act"):

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

Capitalized terms used but not defined herein have the meanings given to them in Eni's annual report on Form 20-F for the year ended December 31, 2023.

ORDINARY SHARES

The following description of our ordinary shares is a summary and does not purport to be complete. It is subject to and qualified in its entirety by the Eni By-laws and by applicable Italian law. A copy of the Eni By-Laws is filed as Exhibit 1 to Eni's annual report on Form 20-F for the year ended December 31, 2023.

General

A s of December 31, 2023, the issued share capital of Eni, a societa' per azioni incorporated under the laws of Italy, amounted to €4,005,358,876 and was represented by 3,375,937,893 ordinary registered shares without indication of par value.

The Company's ordinary shares are in registered form and are freely transferable. As required by the Italian law on the dematerialization of financial instruments, Eni's 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.

The Company's ordinary shares have been listed on the Euronext Milan, the stock exchange regulated and managed by Borsa Italiana S.p.A. . Eni's ordinary shares are part of the FTSE MIB Index.

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.

1

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 both 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 31, 2024, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization), or by the Board of Directors. 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.

Purchase by Eni of its own shares

Pursuant to Italian law, a company may purchase its own shares only upon prior authorization by the shareholders' meeting, which authorization shall set forth the methods of purchase, the minimum and maximum number of shares to be purchased, the duration of the authorization (not to exceed 18 months) and the minimum and maximum price to be paid. The total consideration payable for such shares cannot exceed the total amount of distributable earnings and distributable reserves as reflected in the most recent financial statements approved by the latest annual shareholders' meeting. The company may not purchase shares for an aggregate nominal value, including shared held by subsidiaries, that exceeds one- fifth of the company's share capital. Shares purchased in excess of such limit must be resold within one year from the date of their purchase. Identical limitations apply to purchases of shares of a company by its subsidiaries.

Eni Shareholders' Meeting of May 10, 2023, authorized the Company to repurchase its own shares. See "Item 16E – Purchases of equity securities by the issuer and affiliated purchasers" in Eni's annual report on Form 20-F for the year ended December 31, 2023.

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.

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.

In accordance with 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 containing "Measures to strengthen the National Health Service and provide economic support for families, workers and businesses connected with the COVID-19 epidemiological emergency", and of Decree Law no. 198/2022, ratified with amendments by Law no. 14/2023, that extended the effectiveness of the abovementioned measures also to the Shareholders' Meeting to be held by July 31, 2023, the participation in the Shareholders' Meeting of May 10, 2023 was permitted solely through the Shareholders' representative designated by the Company pursuant to Article 135-undecies of Consolidated Law on Financial Intermediation. Law no. 21 of March 5, 2024 extended the effectiveness of the above-mentioned measures also to the Shareholders' Meeting to be held by December 31, 2024.

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 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 to company assets in the following sectors: defense and national security; broadband electronic telecommunication networks based on 5G technology, cloud-based and other assets relevant to cybersecurity; energy, transport and communications, as defined by the regulations which implement the relevant law.

With reference to the energy sector, 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, 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; there is also an obligation to notify acquisitions that 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 security or public order.

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%.

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 nonfinancial 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 entail 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.

Finally, 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 Intermediation² and the Consob Regulation³ , any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%⁴ , 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.

² Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.

³ Article 117 of Consob Decision No. 11971/1999 and subsequent amendments

⁴ 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.

For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria⁵ . 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 investments⁶ .

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 months⁷ . 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.

⁵ Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.

⁶ Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.

⁷ 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.

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 Authority⁸ 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 preemptive 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.

7

⁸ Autorità garante della concorrenza e del mercato (AGCM).

AMERICAN DEPOSITARY SHARES

General

In 1995, Eni established a sponsored American Depositary Receipts ("ADRs") program directed at U.S. investors. In the United States, Eni's shares are registered with the SEC and are traded in the form of American Depositary Shares ("ADSs") which are listed on the New York Stock Exchange ("NYSE"). ADSs are evidenced by ADRs, and each ADR represents two Eni ordinary shares.

Since June 27, 2017, Citibank N.A. (the "Depositary") is the Company's depositary bank issuing ADRs pursuant to a deposit agreement (the "Deposit Agreement") among Eni, the Depositary and the beneficial owners and registered holders from time to time of the ADRs issued thereunder. The principal office of the Depositary is currently located at 388 Greenwich Street, New York, New York 10013, United States. The custodian is Citibank N.A. (Milan Branch), currently having its principal office at Via Dei Mercanti, 12, 20121 Milan, Italy. Computershare is the transfer agent for the Eni ADR program.

ADSs may be held either directly or indirectly through a broker or other financial institution. If ADSs are held directly, by having an ADS registered in the holder's name on the books of the Depositary, the holder is an ADR holder. If ADSs are held through a broker or financial institution nominee, the holder must rely on the procedures of such broker or financial institution to assert the rights of an ADR holder described in this section. Holders should consult with their broker or financial institution to find out what those procedures are. The following is a summary of the material terms of the Deposit Agreement. Because it is a summary, it does not contain all the information that may be important. For more complete information, holders should read the entire form of Deposit Agreement and the form of ADR, which contain the terms of the ADSs. Please refer to Exhibit 99.(A) on Form F-6 (File No. 333-218170) filed with the SEC May 22, 2017. Copies of the Deposit Agreement are also available for inspection at the offices of the Depositary.

Deposit, withdrawal and cancellation

The Depositary will deliver ADSs if a shareholder or its broker deposit shares with the custodian. Shares deposited with the custodian must also be accompanied by certain documents, including (a) in the case of shares represented by certificates issued in registered form, instruments showing that such ordinary shares have been properly transferred or endorsed, (b) in the case of shares represented by certificates in bearer form, the requisite coupons and talons pertaining thereto, and (c) in the case of book- entry shares, confirmation of book-entry transfer and recordation, in each case to the person on whose behalf the deposit is being made.

The custodian will hold all deposited shares for the account of the Depositary. ADR holders thus have no direct ownership interest in the shares and have only such rights as are contained in the Deposit Agreement. The deposited shares and any other securities, property or cash received by the Depositary or the custodian and held under the Deposit Agreement are referred to as deposited property.

Upon each deposit of shares, receipt of related delivery documentation and compliance with the other provisions of the Deposit Agreement, including the payment of the fees and charges of the Depositary and any taxes or other fees or charges owing, the Depositary will issue and deliver ADSs in the name of the person entitled thereto and, if applicable, issue ADRs evidencing the number of ADSs to which such person is entitled. ADRs will be delivered at the Depositary's principal office.

The depositary will make arrangements for the acceptance of ADSs for book-entry settlement through The Depository Trust Company ("DTC"). All ADSs held through DTC will be registered in the name of Cede & Co., the nominee for DTC. Unless issued as uncertificated ADSs, the ADSs registered in the name of Cede & Co. will be evidenced by one or more ADRs in the form of a "Balance Certificate," which will provide that it represents the aggregate number of ADSs from time to time indicated in the records of the Depositary as being issued to DTC thereunder and that the aggregate number of ADSs represented thereby may from time to time be increased or decreased by making adjustments on such records of the depositary and of DTC or Cede & Co.

8

When holders turn in their ADSs (and, if applicable, the ADRs evidencing the ADSs) at the Depositary's principal office, the Depositary will, upon payment of certain applicable fees, charges and taxes, and upon receipt of proper instructions, deliver the underlying shares. At the holder's risk, expense and request, the Depositary will deliver (to the extent permitted by law) deposited property at the Depositary's principal office.

The depositary may restrict the withdrawal of shares only in connection with: (i) temporary delays caused by closing the transfer books of Eni or those of the Depositary or the deposit of shares in connection with voting at a shareholders' meeting, or the payment of dividends; (ii) the payment of fees, taxes and similar charges; and (iii) compliance with any U.S. or foreign laws or governmental regulations relating to the ADSs or to the withdrawal of shares. The right of withdrawal may not be limited by any other provision of the Deposit Agreement.

Voting procedures

As soon as practicable after receipt of notice of any meeting at which the holders of shares are entitled to vote, or of solicitation of consents or proxies from holders of shares, the Depositary will fix a record date in respect of such meeting or solicitation of consent or proxy in accordance with the Deposit Agreement. The Depositary shall, if requested by the Company in writing (the Depositary having no obligation to take any further action if the request shall not have been received by the Depositary at least 30 days prior to the date of such vote or meeting), distribute to holders as of the record date: (a) such notice of meeting or solicitation of consent or proxy, (b) a statement that the holders at the close of business on the record date will be entitled, subject to any applicable law, the provisions of the Deposit Agreement and the Eni By-laws, to instruct the Depositary as to the exercise of the voting rights pertaining to the shares represented by such holder's ADSs and (c) a brief statement as to the manner in which such voting instructions may be given to the Depositary.

The Depositary may alternatively distribute to the holders a notice that provides instructions on how to retrieve such materials or receive such materials upon request (e.g., by reference to a website containing the materials for retrieval or a contact for requesting copies of the materials), to the extent not prohibited by law or regulations, the Eni By-laws or by applicable stock exchange requirements.

Voting instructions may be given only in respect of a number of ADSs representing an integral number of shares. Upon the timely receipt of voting instructions from a holder of ADSs, the Depositary will endeavor to vote, or cause the custodian to vote, the shares represented by such holder's ADSs in accordance with the voting instructions. Shares represented by ADSs for which no timely voting instructions are received by the Depositary from the holder will not be voted. Neither the Depositary nor the custodian will exercise any discretion as to voting and neither the Depositary nor the Custodian will vote shares represented by ADSs except pursuant to and in accordance with the voting instructions timely received from holders or as otherwise contemplated in the Deposit Agreement. If the Depositary timely receives voting instructions from a holder which fail to specify the manner in which the Depositary is to vote the shares represented by such holder's ADSs, the Depositary will deem such holder to have instructed the Depositary to vote in favor of the items set forth in the voting instruction, unless otherwise specified in the notice distributed to holders. Notwithstanding anything else contained in the Deposit Agreement, the Depositary shall, if so requested in writing by the Company, represent all shares represented by the ADSs (whether or not voting instructions have been received in respect of such shares from holders as of the ADS record date) for the sole purpose of establishing quorum at a meeting of shareholders.

There can be no assurance that holders generally or any holder in particular will receive the notice described above with sufficient time to enable the holder to return voting instructions to the Depositary in a timely manner.

The Depositary will not have any obligation to any holder or the Company to take any action with respect to (i) any meeting, or solicitation of consents or proxies, of holders of shares, or (ii) any vote of the ADSs or the shares represented thereby, if the taking of such action by the Depositary would violate or be limited by applicable law, or the provisions of the Eni By-laws, or if the Depositary, upon advice of its counsel, reasonably believes that its taking of such action would be such a violation or so limited.

Share dividends and other distributions

Eni may make various types of distributions with respect to its securities. The Depositary has agreed to pay to each holder the cash dividends or other distributions it or the custodian receives on ordinary shares, after deducting its fees and expenses. Each holder will receive these distributions in proportion to the number of underlying ordinary shares that its ADSs represent.

Except as stated below, to the extent the depositary is legally permitted it will deliver such distributions to ADR holders in proportion to the number of ADSs held at the relevant record date in the following manner:

Cash. Upon receiving notice from Eni that Eni intends to distribute a cash dividend or other cash distribution, the Depositary will establish a record date for such distribution. As promptly as practicable following the receipt of a cash dividend or other cash distribution from Eni, the Depositary will: (i) if at the time of receipt thereof any amounts received in a foreign currency can, in the judgment of the depositary, be converted on a practicable basis into U.S. dollars transferable into the United States, promptly convert or cause to be converted such cash dividend or cash distributions into U.S. dollars, (ii) if applicable, establish a record date for the distribution and (iii) distribute promptly such U.S. dollar amount, net of applicable fees, charges and expenses of the Depositary and taxes withheld. The depositary shall distribute only such amount as can be distributed without attributing to any ADR holder a fraction of one cent. Any balance not so distributed shall be held by the Depositary (without liability for interest thereon) and shall be added to and become part of the next sum received by the Depositary for distribution to holders of ADSs outstanding at the time of the next distribution. If at any time the Depositary shall determine that in its judgment the conversion of any foreign currency and the transfer and distribution of proceeds of such conversion received by the Depositary is not practicable or lawful, or if any approval or license of any governmental authority or agency thereof that is required for such conversion, transfer and distribution is denied or, in the opinion of the Depositary, not obtainable at a reasonable cost or within a reasonable period, the Depositary may, in its discretion, (i) make such conversion and distribution in U.S. dollars to the holders for whom such conversion, transfer and distribution is lawful and practicable, (ii) distribute the foreign currency (or an appropriate document evidencing the right to receive such foreign currency to holders for whom this is lawful and practicable, or (iii) hold (or cause the custodian to hold) such foreign currency (without liability for interest thereon) for the respective accounts of the holders entitled to receive it.

Notwithstanding anything contained in the Deposit Agreement to the contrary, if the Company fails to give the Depositary timely notice of the proposed cash distribution, the Depositary agrees to use commercially reasonable efforts to perform the actions contemplated in the Deposit Agreement for cash distributions. The Depositary shall have no liability for the failure to perform such actions where the notice has not been so timely given, other than for its failure to use commercially reasonable efforts.

Shares. Upon receiving notice from Eni that Eni intends to distribute a share dividend or free distribution of ordinary shares, the depositary will establish a record date for such distribution. The depositary will then either (i) deliver additional ADSs representing such ordinary shares, or (ii) if additional ADSs are not so distributed, take all actions necessary so that each ADS issued and outstanding after the ADS record date shall, to the extent permissible by law, thenceforth also represent rights and interests in the additional ordinary shares distributed, in each case net of applicable fees, charges and expenses of the depositary and taxes withheld. Only whole ADSs will be issued. Any ordinary shares which would result in fractional ADSs will be promptly sold and the proceeds (net of fees, charges and expenses of the depositary and taxes withheld) will be distributed to the ADR holders entitled to them.

Rights to receive additional shares. Upon receiving notice from Eni that Eni intends to distribute rights to subscribe for additional ordinary shares or other rights and that Eni wishes such rights to be made available to holders of ADSs, the Depositary shall consult with the Company to determine, and the Company shall assist the Depositary in its determination, whether it is lawful and reasonably practicable to make such rights available to the holders. If the Depositary, in consultation with the Company, determines that such distribution of rights is lawful and reasonably practicable, the Depositary will establish a record date for such distribution and establish procedures to distribute the rights to purchase additional ADSs (by means of warrants or otherwise) or to enable the holders to exercise such rights and deliver ADSs upon the valid exercise of such rights. If the Depositary, in consultation with the Company, determines that such distribution of rights is not lawful and reasonably practicable or if the Company requests that the rights not be made available to holders of ADSs, the Depositary shall proceed with the sale of the rights and distribute the proceeds of the sale to the holders entitled to them. If the Depositary is unable to make any rights available to holders or to arrange for the sale of the rights upon the terms described, the Depositary shall allow such rights to lapse.

There can be no assurance that ADR holders will be given the opportunity to receive or exercise rights on the same terms and conditions as the holders of shares or be able to exercise such rights. Nothing will obligate the Company to file any registration statement in respect of any rights or shares or other securities to be acquired upon the exercise of such rights.

Other Distributions. Upon receiving notice from Eni that Eni intends to distribute property other than those described above and that Eni wishes such distribution to be made available to holders of ADSs, the Depositary shall consult with the Company to determine whether such distribution is lawful and reasonably practicable. To the extent the depositary deems distribution of such property to be lawful and practicable, the Depositary may choose any practical method of distribution. If the Depositary deems distribution of such property not to be practicable, after consultation with Eni, the Depositary may sell or cause such property to be sold and distribute the net proceeds. If the Depositary is unable to sell such property, the Depositary may dispose of such property for the account of the holders in any way it deems reasonably practicable under the circumstances. There can be no assurances that the Depositary will be able to convert any currency at a specified exchange rate or sell any property, rights, shares or other securities at a specified price, nor that any of such transactions can be completed within a specified time period.

Reports and other communications

The Depositary will make available for inspection by holders any reports and communications from Eni that are both received by the Depositary as holder of deposited property and made generally available by Eni to the holders of deposited property. In certain cases provided for in the Deposit Agreement, the Depositary will also provide or make available to holders copies of such reports furnished by the Company.

Reclassifications, recapitalizations and mergers

If Eni takes actions that affect the shares, including any change in nominal or par value, split-up, cancellation, consolidation or other reclassification of shares or any recapitalization, reorganization, merger, consolidation, sale of assets or other similar action, then the Depositary may, with the Company's approval, and will if the Company requests so, issue and deliver additional or amended ADRs and take such other actions as are appropriate to reflect the transaction with respect to the ADSs and any property which will be received by the Depositary or the custodian in exchange for, or in conversion of, or replacement of, or otherwise in respect of, such shares pursuant to any of the foregoing actions will, to the extent permitted by law, be treated as new deposited property under the Deposit Agreement, and the ADSs shall, subject to the provisions of the Deposit Agreement, any ADR(s) evidencing such ADSs and applicable law, represent the right to receive such additional or replacement deposited property. If any deposited property may not be lawfully distributed to some or all holders, the Depositary may, with the Company's approval, and will, if the Company requests so, sell such deposited property and distribute the proceeds (net of fees and charges of, and expenses incurred by, the Depositary and taxes, duties and governmental charges) to the holders entitled thereto.

Amendment and termination

Eni may agree with the Depositary to amend the Deposit Agreement and the ADSs without the holders' consent for any reason. ADR holders must be given at least 30 days' notice of any amendment that imposes or increases any fees or charges (other than charges in connection with foreign exchange control regulations, and taxes and other governmental charges, delivery and other such expenses), or affects any substantial existing right of ADR holders. If an ADR holder continues to hold ADRs when an amendment has become effective, such ADR holder is deemed to agree to such amendment.

No amendment will impair the holders' right to surrender their ADSs and receive the underlying securities except to comply with mandatory provisions of applicable law. The Depositary will terminate the Deposit Agreement if Eni requests so. The Depositary may also terminate the Deposit Agreement if the Depositary has notified the Company that it would like to resign and the Company has not appointed a new depositary bank within 90 days. In either case, the Depositary must notify holders at least 30 days before termination. After termination, the Depositary's only responsibility will be (i) to collect dividends and other distributions on the shares, (ii) to sell deposited property received in respect of the shares and (iii) to deliver the shares, together with any distributions received and the net proceeds of the sale of any other deposited property upon surrender of the ADSs. At any time from the termination date, the Depositary may sell the deposited property which remains and hold the net proceeds of such sales and any other cash it is holding under the Deposit Agreement, without liability for interest, for the pro rata benefit of holders who have not yet surrendered their ADRs. After making such sale, the Depositary shall have no obligations except to account for such proceeds and other cash. The Depositary will not be required to invest such proceeds or pay interest on them.

Books of depositary

The Depositary or its agent will keep books for the registration of ADSs which will be open for inspection by the holders during regular business hours, but solely for the purpose of communicating with other holders in the interest of business matters relating to the Deposit Agreement. The Depositary may close the transfer books from time to time when the Depositary considers it expedient to do so.

Limitations on obligations and liability to ADR holders

The Deposit Agreement expressly limits the obligations and liability of the Depositary, Eni and their respective agents. Neither Eni nor the Depositary assumes any obligation nor shall either of them be subject to any liability under the Deposit Agreement to any ADR holder, except that they each agree to perform their respective obligations specifically set forth in the Deposit Agreement without negligence or bad faith. Neither Eni nor the Depositary will be liable: if it is prevented or forbidden from performing anything required by the terms of the Deposit Agreement by reason of law, regulation, the Eni By-laws, the provisions of or governing the shares, act of God, war or other circumstance beyond its control; if it exercises or fails to exercise discretion permitted under the Deposit Agreement, the Eni By-laws or the ADR; if it takes any action or inaction in reliance upon the advice of or information from legal counsel, accountants, any person presenting shares for deposit, any holder, or any other person believed by it to be competent to give such advice or information; if any holder is unable to benefit from any distribution or other benefit which is made available to holders of shares, but is not made available to holders of ADSs under the terms of the deposit agreement; or for any special, or any special, consequential, indirect or punitive damages (including lost profits) for any breach of the terms of the Deposit Agreement.

In the Deposit Agreement, Eni agrees to indemnify the Depositary for acting as depositary, except for losses caused the Depositary's own negligence or bad faith, and the Depositary agrees to indemnify Eni from losses incurred in connection with the Deposit Agreement and resulting from the Depositary's negligence or bad faith.

The Depositary will not be responsible for failing to carry out instructions to vote the shares or for the manner in which the shares are voted or the effect of the vote.

Certification

I, Claudio Descalzi, certify that:

• 1. I have reviewed this Annual Report on Form 20-F of Eni SpA;
• 1. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
• 1. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;
• 1. The company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:
  2. (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
  3. (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
  4. (c) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
  5. (d) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and
• 1. The Company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions):
  2. (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and
  3. (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal control over financial reporting.

Date: April 5, 2024

/s/CLAUDIO DESCALZI

Claudio Descalzi Title: Chief Executive Officer

Certification

I, Francesco Esposito certify that:

• 1. I have reviewed this annual report on Form 20-F of Eni SpA;
• 1. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
• 1. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;
• 1. The company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:
  2. (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
  3. (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
  4. (c) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
  5. (d) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and
• 1. The company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions):
  2. (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and
  3. (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company's internal control over financial reporting.

Date: April 5, 2024

/s/FRANCESCO ESPOSITO

Francesco Esposito Title: Head of Accounting and Financial Statements

Certification Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the "Company"), hereby certifies, to such officer's knowledge, that:

• (i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2023 (the "Report") fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and
• (ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 5, 2024

/s/CLAUDIO DESCALZI

Claudio Descalzi Title: Chief Executive Officer

The foregoing certification 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.

Certification Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the "Company"), hereby certifies, to such officer's knowledge, that:

• (i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2023 (the "Report") fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and
• (ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 5, 2024

/s/FRANCESCO ESPOSITO Francesco Esposito Title: Head of Accounting and Financial Statements

The foregoing certification 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.

Report on the Remuneration Policy and Remuneration Paid 2023

Mission
We are an energy company.
We concretely support a just energy transition,
with the objective of preserving our planet
and promoting an efficient and sustainable access to energy for all.
Our work is based on passion and innovation,
on our unique strengths and skills,
on the equal dignity of each person,
recognizing diversity as a key value for human development,
on the responsibility, integrity and transparency of our actions.
We believe in the value of long-term partnerships with the Countries
and communities where we operate, bringing long-lasting prosperity for all.

Global goals for a sustainable development

The 2030 Agenda for Sustainable Development, presented in September 2015, identifies the 17 Sustainable Development Goals (SDGs) which represent the common targets of sustainable development on the current complex social problems. These goals are an important reference for the international community and Eni in managing activities in those Countries in which it operates.

Eni Report on the 2024 Remuneration Policy and Remuneration Paid 2023

Approved by the Board of Directors on April 4, 2024

The Report is published in the "Governance" and "Publications" sections of the Company website (www.eni.com).

Contents

LETTER FROM THE CHAIRMAN OF THE REMUNERATION COMMITTEE
INTRODUCTION	6
EXECUTIVE SUMMARY	8
SECTION I - 2024 REMUNERATION POLICY	20
Section subject to the binding vote of the 2024 Shareholders' Meeting
Main changes in the Policy	20
Corporate governance	20
Bodies and parties involved	20
Engagement on Remuneration Policy	21 21
Eni Remuneration Committee	25
2024 Remuneration Policy approval process Purpose and general principles of the Remuneration Policy	25
Purpose	25
General principles	26
2024 Remuneration Policy	27
Connection with corporate strategy	27
Market benchmarks and remuneration Peer Group	78
Employees' remuneration and working conditions	ਤਰੇ
Employee Stock Ownership Plan 2024-2026	29
Officers covered by the Policy	30
Chairman of the Board of Directors	30
Non-executive Directors	30
Board of Statutory Auditors	30
Chief Executive Officer and General Manager	31
Managementin Stratanic Dacementily litige	20

SECTION II - REMUNERATION AND OTHER INFORMATION	42
This section is subject to a non-binding vote of the 2024 Shareholders' Meeting
Introduction	42
Disclosure on remuneration changes	47
Implementation of the 2023 remuneration policies	Lake.
Verlfication of 2023 performance for the purpose of the accrual of incentives payable and/or granteble in 2024	44
Remuneration accrued and/or awarded in 2023	46
Additional disclosure on the implementation of Remuneration Policy for 2022	50
Remuneration accrued in 2023	ದಿನ
Table I - Remuneration accrued to Directors, Statutory Auditors, the Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with Strategic Responsibilities	નર
Table 2 - Monetary Incentive Plans for the Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with Strategic Responsibilities	56
Table 3 - Incentive plans based on financial instruments other than stock options, for the Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with Strategic Responsibilities	58
Shareholdings held	60
Table 4 - Shareholdings held by Directors, Statutory Auditors, the Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with Strategic Responsibilities	60
Annex under Article B4-bis of Consob Issuer Regulation - 2023 Implementation of the 2023-2025 Long-Term Incentive Plan (LTI)	പി
Table No. 1 of Schedule 7 of Annex 3A to Regulation No. 11971/1999	61

ANNEX: LIST OF CHARTS AND TABLES

63

Letter from the Chairman of the Remuneration Committee

Massimo Belcredi Chairman of the Remuneration Committee

Dear Shareholders.

For Eni, 2023 was a year of excellent results achieved in an uncertain and volatile environment, in which the company successfully continued on its path of industrial transformation, in line with its adopted strategy, focused in particular on the energy transition and decarbonisation.

At the same time, Eni continued to pay the utmost attention to its People, including through the establishment of an extraordinary plan to support employees, which provided for a series of salary measures (an extraordinary one-off payment, fuel bonus, discount on gas and electricity utilities), in consideration of the loss of purchasing power caused by high inflation.

In this context, I am also pleased to announce the introduction - in the Eni Remuneration Policy - of a Employee Stock Ownership Plan aimed at all employees, which will be implemented in the period from 2024-2026. This Plan made it necessary to update the Policy for 2024, which is then submitted for approval to the Shareholders' Meeting of 15 May 2024, together with the related Information Document.

The purpose of the Employee Stock Ownership Plan is to strengthen Eni people's sense of belonging to the company and promote their participation in the company's objectives and growth in value, in line with shareholders' interests.

Remuneration Policy for 2024

First of all, the new Remuneration Committee played its role, both proactive and advisory, in the application of the 2023-2026 Remuneration Policy, drafted at the end of the previous Board term, in line with the recommendations of the Corporate Governance Code, to which the company adheres.

The decision to launch the Employee Stock Ownership Plan entailed the need to amend the Policy. in relation to the participation in the Plan of the Chief Executive Officer and General Manager and of Managers with Strategic Responsibilities (limited to the symbolic grant of one share). Against this backdrop, the Committee, having appreciated the high approval level for the 2023-2026 Policy, which exceeded 90%, decided to continue along the line outlined by the previous Board and Shareholders' Meeting and not propose any further changes of substance. Therefore, the Policy for 2024 keeps the structure and remuneration levels of directors and management unchanged, with the only substantial change being the Employee Stock Ownership Plan. Additionally, the Clawback Regulation was updated, using the terms requested in the recent SEC/NYSE regulation, for cases of "accounting restatement".

Shareholder engagement

Also for the new mandate, the Committee intends to ensure clear, correct, timely and complete communication with Proxy Advisors and Institutional Investors, with the utmost openness to dialogue and in compliance with the principle of equal information and applicable regulations for the handling and disclosure of documents and information concerning the Company.

ANNEX

In performing its functions, the Remuneration Committee, immediately after its inauguration, scheduled two rounds of meetings in which I participated directly. The purpose of these meetings was not only to present the new composition of the Committee, but also to engage in dialogue with the market on issues within the Committee's remit, under the terms set out in the Policy for Managing Dialogue with Investors. The Committee intends to continue this dialogue in order to answer questions from investors and receive input on possible future developments in the Policy.

Results in 2023

The implementation of remuneration policies in 2023 reflects Enl's excellent financial and operational performance, as well as the implementation of its energy transition and decarbonisation strategy. In particular, the remuneration of the Chief Executive Officer and General Manager is strongly correlated to trends in the company's results and the value created for shareholders,

This evidence shows that Enl's Remuneration Policy contributes to the achievement of strategic objectives and aligns with the interests of shareholders and stakeholders, through an incentive system characterised, both in the short and long term, by balanced metrics - financial and nonfinancial - that also give significant weight to environmental and energy transition objectives.

Conclusion

It is a pleasant duty for me to thank the other members of the Committee, Cristina Sgubin and Raphael Vermeir, for their constant availability and the contribution they have always made, thanks to their great wealth of professionalism and experience.

Dear Shareholders, I leave you to read the Report on the 2024 Remuneration Policy and on Remuneration Paid 2023. I trust in your continued support for the Eni Remuneration Policy, also with respect to the introduction of the Employee Stock Ownership Plan for all employees.

March 4, 2024

Massimo Belcredi Chairman of the Remuneration Committee

Introduction

The introduction of a Employee Stock Ownership Plan for all employees made it necessary to update the Remuneration Policy for 2024, which will therefore be submitted to the 2024 Shareholders' Meeting for a vote.

This Report on the Remuneration Policy 2024 and on Remuneration Paid 2023 (hereafter, the 'Report' or the "Remuneration Report") was approved by the Board of Directors on April 4, 2024, based on a proposal from the Remuneration Committee, in compliance with current legal and regulatory requirements', with an annual duration in relation to potential developments in the regulatory, organisational and business scenarios.

The Report includes:

Section I - subject to the binding vote of the 2024 Shareholders' Meeting

Section II - subject to the non-binding vote of

the 2024 Shareholders'

Meeting

· in the first section, a description of the Remuneration Policy for 2024, adopted by Eni SpA (hereafter, 'Eni' or the "Company") for the Directors, Statutory Auditors, Chief Operating Officers and Other Managers with Strategic Responsibilities', subordinate to approval by the Shareholders' Meeting on May 15, 2024 (binding vote), called to approve the annual financial statements at December 31, 2023. The first section also includes a description of the Employee Stock Ownership Plan for all employees, including the Chief Executive Officer/General Manager and Managers with Strategic Responsibilities.

Finally the section describes the corporate bodies involved and the procedures used for the adoption. implementation and possible revision of the Policy and the purposes and general principles that also apply to the remuneration policies of the companies directly and indirectly controlled by Eni2, with the exclusion of the listed subsidiaries (also jointly controlled), directly required to apply the legislation.

The Remuneration Policy has been prepared in line with the principles and the recommendations of the Corporate Governance Code+ as well as the additional indications of the Corporate Governance Committee®

· in the second section, the implementation of the Policy applying in 2023, with the information on the final results and an indication of the remuneration accrued and the equity investments held, in individual form for the Directors, Statutory Auditors and Chief Operating Officers, and in aggregate form, for the other Managers with Strategic Responsibilities, which will be submitted to the 2024 Shareholders' Meeting for a non-binding vote.

Finally, the section presents, for the 2023-2025 Long-Term Incentive Plan, information on implementation in 2023, in line with current regulations®.

The two sections of the Report are introduced by an Executive Summary that provides an overview of the Remuneration Policy for 2024 and some background information

(6) Art. 114-bis of the Consolidated Law on Financial Intermediation and Art. 84-bis of the Consol Issuers Regulation

⁽¹⁾ Art.123-ter of Italian Legslative Decree 58/98 (Consolidated Law on Financial Intermediation), as amended by Art. 3 of Legstatuve Decree 49 of May 10, 2019, and At. 84-quater of the Consocio Issuers Regulation (Reschtion no. 11971/99 and subsequent) amendments and additions).

^(2). Those persons who have the power and responsibility, directly or indrectly, for planning, directing and controlling Enl fail under the definition of "Manages with Strategio Responsibilities", in accordance with Art. 65, paragraph 1-quaser of the Issuers Regulation. Enl Managers with Strategic Responsibilities, other than Drestors and Statutory Auditors, are those who report directly to the Chef Executive Officer and Chairman of Eri and, in any case, those who sit on the Management Committee. For more information on the organisational structure of Eni, see the Company's website (www.eni.com).

⁽³⁾ The remuneration policies of the subsidiaries are determined in respect of the principle of their management autonomy, in particular for comparies subject to regulation, as well as in accordance with the provisions of local legislation

⁽⁴⁾ For further information on the terms of adaption of Edits Governance Code, piesse. refer to Eni Corporate Governance and Shareholdings Structure Report as well as the section "Corporate Governance" on the Company website. (5) See the December 15, 2023 press release available on the Borga Italiana website

ANNEX

The text of this Report will be published no later than twenty-one days before the date of the Shareholders' Meeting at which shareholders will be invited to approve the 2023 financial statements as well as to express a binding vote on the first section of the Report and, with a non-binding resolution, on the second section, in accordance with applicable regulations".

The text of the Report is available at the Company's registered headquarters, on the Company website in the sections "Governance" and "Publications", and via the website of the provider of disclosure and storage services for regulated information "Info" (available at ).

As required by law?, PricewaterhouseCoopers S.p.A., which is in charge of the statutory audit, verfied the preparation of the second section of the Report.

The documents relating to existing remuneration plans based on financial instruments are available in the "Corporate Governance" section of the Company website.

(7) Art. 123-ter of the Consolidated Law on Francial Intermediation, as modified by Art. 3 of Italian Legistire Decree 49/19

(8) Art 123-tec paragraph B-bis, of the Consolidated Law on Financial Internediation, is modified by Art. 3 of Italian Legislative Decree 49/19.

(paragraphs 3-bis, 3-ter and 6, in particular).

Executive Summary

CONTENTS

SUMMARY INDICATORS FOR 2023

2024 REMUNERATION POLICY AND CONNECTION WITH THE COMPANY'S BUSINESS MODEL AND STRATEGY

RESULTS OF THE SHAREHOLDERS' VOTE The purpose of the Executive Summary is to provide to the market an overview of the trend in the market results (TSR) and the main indicators of environmental sustainability and humancapital (accidents, GHG emissions, pay ratio and minimum wages) and an analysis of pay for performance.

The Summary also briefly presents the Remuneration Policy for 2024, the connection with the Eni strategy and the results of the shareholders' vote on the Remuneration Policy and on its implementation in the previous years.

ANNEX

SUMMARY INDICATORS FOR 2023

TSR In the 2015-2023 period. Eni delivered a Total Shareholder Return (TSR) of +66.6%; compared to Total Shareholder Return +64.8% for the Peer Group®, while the FTSE MIB produced a TSR of +98.6%, compared to an average of +56.2% for the peer companies' respective benchmark stock market indices.10

CHART 1 - TOTAL SHAREHOLDER RETURN (ENI VS. PEER GROUP AND BENCHMARK STOCK MARKET INDICES)

SIR: In 2023, the Severity Incident Rate (SIR) saw a clear improvement with respect to the previous year, thanks to a drop in the most serious injuries. Eni's Total Recordable Injury Rate (TRIR) also improved on the previous year, still the "best in class" among its Oil & Gas peers (the second in the ranking, TotalEnergies, reported a TRIR of 0.67 in 2022 vs. Eni's 0.41).

Severity Incident Rate

CHART 2 - TOTAL RECORDABLE INJURY RATE® (TRIR) AND SEVERITY INCIDENT RATE® (SIR)

Total Recordable Injury Rate (TRIR) - Severity Incident Rate (SIR)

(a) Total recordable injuries/hours worked x 1,000,000.

(b) Total recordable injuries weighted for severity/hours worked x 1,000,000.

(c) in 2023, the indicator also measures managements connitiment to developing a salety culture, through projects, verying the reasive implementation and internalisation of the behaviours requested.

(9) The Peer Group consists of: BP, Equinor, OMV, Repsol, Shell and TotalEnergies,

(10) Benchmark inclices are: Cac 40, FTSE 100, AEX and OBX.

GHG emissions

Net GHG emissions of upstream operated and non-operated equity (Scope 1+2): Net Scope 1+2 Equity Upstream emissions amounted to 8.9 MtCO,eq. in 2023, down by around 10% with respect to the final figure for 2022 (9.9 MTCO,eq.). The result benefited from actions to optimise operating management and improve efficiency. The chart also shows the trend for the GHG Scope 1 and 2 emission intensity equity parameter.

CHART 3 - NET GHG EMISSIONS UPSTREAM SCOPE 1 AND 2 EQUITY AND GHG EMISSION INTENSITY SCOPE I AND SCOPE 2 UPSTREAM EQUITY

Eni Total Remuneration Positioning vs. Peer Group

Total target remuneration of the Eni Chief Executive Officer in 2023 is classified in 10th place with respect to the CEOs of the companies in its Peer Group.

CHART 4 - TOTAL AVERAGE REMUNERATION 2023 (THOUSANDS OF EURO)

(a) Policy target indicated in the Remuneration Reports of the companies, converted to euro at the exchange rate at Deoember 30.

The comparison between the trend of TSR and total CEO/GM remuneration in the 2015-2023 period shows a good correlation.

LETTER		INTROQUCTION EXECUTIVE SUMMARY SECTION 1		SECTION II	ANNEX
--------	--	------------------------------------------	--	------------	-------	--

CHART 5 - PAY FOR PERFORMANCE ANALYSIS (EN) TSR VS. TOTAL REMUNERATION FOR CEO/GM 2015-2023)

CEO/GM pay ratio vs. median employee remuneration: below reports the pay ratios between the CEO/GM pay ratio remuneration of the Chief Executive Officer and General Manager and the median remuneration of employees in Italy and globally, calculated in reference to both the fixed remuneration and the total. remuneration™. The total remuneration ratio is increased with respect to 2022, mainly reflecting the change in the Long-Term Stock Incentive granted in 2023, in relation to the increase in the Eni share price at the time of the grant with respect to that when awarded (€15.27 vs. €8.21).

vs. median employee remuneration

11

TABLE 1 - CEO/CM PAY RATIO VS. MEDIAN EMPLOYEE REMUNERATION

Employees in Italy	2020	2021	2022	2023
Ratio between fixed remuneration of the CEO/GM and median fixed remuneration of employees.	37	36	35	35
Ratio between total remuneration of the CEO/GM and median total remuneration of employees	97	138	137	172
All employees
Ratio between frood remunesation of the CEO/GM and median fined remoneration of employees .	36	36	35	36
Ratio between total remuneration of the CEO/GM and median total remuneration of employees	97	141	140	100

Gender pay ratio the gender pay ratio data for fixed and total remuneration, at the general level Gencher pay ratio and by professional category. ("raw" pay ratio) are shown. They show a substantial alignment between the salaries of the female and male populations for the Italian and global population, with differences in some categories mainly attributable to a lower presence of women. With respect to the 2022 figures, the data are mainly unchanged with a variation in the Blue collar Italy category due to the entry of female workers from sectors utilising collective bargaining agreements with lower salary references than the reference contract for Eni.

TABLE 2 - RAW GENDER PAY RATIO™

	Fiscad remuneration		Total remuneration.
	2022	2023	2022	2023
Employees in Italy"
Total pay ratio (women memors)	102	102	98	97
Serior Managers	BE	87	79	79
Middle Monagers and Senior Staff	97	07	ਹੋਈ	aa
White collars	102	101	103	101
Blue collars	91	B2	91	85
All employees'4
Total pay ratio (women vs. men)	101	101	97	97
Senior Managers	85	87	80	79
Middle Managers and Senior Staff	ਹੈ ਕੋ	તેવ	92	da
White collars	100	ਰੇਜ਼	100	48
Blue collars	92	ੋਹ	23	da

(i).The gender pay ativ is called antific issues in the secure remators of an and the second security of min

Considering the same role level in each professional category, according to the United Nations principle "equal pay for equal work" (Table 3), the alignment between the remuneration of women and men is clearer, with statistically negligible and substantially stable differences over the years.

TABLE 3 - GENDER PAY RATIO WITH EQUAL ROLES AND SENIORITY®

	Exect remuneration				Total remuneration
	2020	2021	2022	2023	2020	2021	2022	2023
Employees in Italy
Total pay ratio (women vs. men)	08	99	00	99	99	100	100	100
Senior Managers	97	98	ਨੇਤੇ	98	97	ਰਜ	100	98
Middle Managers and Serier Staff	97	08	08	99	97	08	00	100
White collars	101	107	101	100	101	102	102	100
Blue collars	ਰੇ ਦੇ	વેલ	વેટ	94	dia	ਉਹ	95	98
All employees
Total pay ratio (women vs. men)	98	ರೆದಿ	ેન્ક	98	ਸੋਰੋ	00	09	dd
Serior Managers	97	98	00	98	dia	વેલું	ිට	98
Middle Managers and Senior Staff	97	08	ੈਰੋਜ਼	99	97	08	00	100
White collars	100	100	00	ਰੇਸ਼	100	100	100	ਹੈ ਕੇ
Blue collars	00	વેઠ્	di-	હેવું	તેમ્	06	ටිව	95

(a) The gender pay ratio is calculated as the ratio between the average renunerstips of women and the everage mountrion of men

Minimum Wage: For each country in which it operates, Eni's policy remuneration standards are well Minimum wages above the legal/contractual minimums, as well as in the 18 decile12 of the local remuneration market. We annually check our positioning in terms of remuneration, adopting any necessary corrective actions. The table shows a comparison between the 1ª decile of Eni, the 1ª decile of the market and the legal minimum for the main Countries where Eni is present, both expressed as percentages.

TABLE 4 - MINIMUM WAGES

		Ratio of Eni 1e decile to statutory minimum wage™
Country	Ratio of Eni 1ª decile to market 1" decile"	women	men	total
Italy		11	an	1
Agerial			2
Austra
Belgium
China			2
Foundar			1
Egypt			1
France			3
Gennamy
Ghana	17
Inconesia
Nigeria	o				Key
Turisia					Eni minimum > 2:50% of minimum benchmark.
Hurigary.					En minimum between 201% and 250% of minimum benchmark.
United Kingdom					Eni minimum between 151% and 200% of minimum benchmark.
United States					En minimum between 110% and 150% of minimum benchmark.

(t) Misimum salaries as delived by law in the various countries or, it not applicable, in national collective bargaining aggessments.

2024 REMUNERATION POLICY AND CONNECTION WITH THE BUSINESS MODEL AND STRATEGY

En's business model is focused on creating value for its stakeholders through a strong presence along the whole energy value chain; from exploration, development and extraction of oil and natural gas, to the peneration of electricity from copeneration and renewable sourges, to traditional and bio refining and chemistry, up to the development of circular economy processes and markets as well as retail and business customers. Eni aims at contributing, directly to achieve the Sustainable Development Goals (SDGs) of the UN 2030 Agenda, supporting a just energy transition, responding through concrete and economically sustainable solutions to the challenge of combating climate change and giving access to energy resources for all in an efficient and sustainable way.

^(*) As of December 31, 2023 or in 2023, unless stated otherwise

(**) People involved in local projects could have benefitted from more than one intilative in different areas of opportunity.

ANNEX

The Remuneration Policy supports the achevement of the goals set in the Company's Strategic Plan by promoting, through a balanced use of performance measures in the short and long-term incentive systems, the alignment of senior management's interests with the priority of creating sustainable value for shareholders over the medium to long-term.

The 2023-2025 Long-Term Equity based Incentive Plan guidelines by providing a specific environmental sustainability and energy transition goal (with an overall weight of 35%), made up of targets related to decarbonisation, energy transition and circular economy.

TABLE 5 - ALIGNMENT WITH THE STRATEGIC PLAN

	5TRATEGIC DRIVERS	ENVIRONMENTAL SUSTAINABILITY	ENERGY SECURITY	AFFORDABILITY
	Economic and financial results (25%)	1	V	V
	Operating results (25%)	V	V	V
	Environmental sustainability and human capital (25%)	V
	Efficiency and financial soundness (25%)	1	V	V
	Normalised TSR (25%)	V	V	N
	Organic Free Cash Flow (40%)	1	V	V
	Decarbonisation (10%)	V
	Energy transition (15%)	1	V	V
	Circular economy (10%)	V	V	2

VALUE CREATION FOR SHAREHOLDERS AND OTHER STAKEHOLDERS

TABLE 6 - OUR GOVERNANCE PRACTICES

WHAT WE DO

• · Variable incentive plans linked to measurable and predetermined, financial, targets, consistent with the Strategio Plan
• · Pay mix of executive roles characterized by significant long-term components
• · Performance assessed both in absolute terms and in comparison with industry peers
• · Long-term incentive vesting periods of no less than 3 years, and look-up clauses for equity instruments
• · Malus and clawback clauses in the event of eror, bad faith or serious, intentional violations of the Code of Ethics and Company rules
• · Structured engagement plan to respond to the expectations and feedback of our shareholders

WHAT WE DON'T DO

• · No remuneration higher than national and international market benchmarks
• · No forms of variable remuneration for non-executive Directors
• · No extraordinary incentives for the CEO/GM
• · No severance package that exceeds the limits set for by labour agreements and applicable law
• · No benefits of excessive value, limited to healthcare and pension benefits

TABLE 7 - 2024 REMUNERATION POLICY SUMMARY

The 2024 Enl Remuneration Policy for Directors, Audtors, Chief Operating Officers and Other Maragers with Strategic Responsibilities was approved by the Board of Directors on April 4, 2024 and, keeping remuneration levels unchanged with respect to the previous Policy, has one substantial. imovation which is the introduction of a Employee Stock Ownership Plan (ESOP) for all employees. The Polcy is intended to attract and retain individuals of high managerial standard, and motivate them to achieve sustainable long-term objectives.

MARKET REFERENCES

Chief Executive Officer and General Manager (GM):

Remuneration Per Group consisting of Europen companies in the Energy and Uillies sector and other companible industrial sectors (Stell, TotalErerges 8P, Report Equinor, OMV, RWE, Iberdrola, E.ON, ENGE, Enel, BASE Bayer, Rio Tinto, Anglo American, Volkswagen, Vodafone, Siemers),

Chief Operating Officers and Other Managers with Strategic Responsibilities (MSRs):

Selected markets within the national industrial sector for roles with the same level of responsibility.

FIXED REMUNERATION
PURPOSE AND CONDITIONS	Reward skills, experience and responsibility
CRITERIA AND PARAMETERS	CEO: Fired remainer of C / 60,000, equal to that in the 2020-2023 term in relation to responsibilities and powers assigned and the continuation of the employment relationship.
	MSRs: Fixed remuneration is based on the role assigned, potentially adjustted to median market remuneration level.
	SHORT TERM INCENTIVE PLAN
PURPOSE AND CONDITIONS	Motivate to achieve annual targets in a perspective of medium/long-term sustainability The Plan is subject to malus/clawback conditions. 2024 targets for CEO: 1. Economic and financial results: EBT (12.5%); organic Free Cash Flow (12.5%); 2. Operating results: production of hydrocarbons (72.5%); incremental installed renewable capacty (12.5%), 3. Environments! sustainability and human capital upstream GHG net enrissions Scope 1 and Scope 2 equity (12.6%); Severly Incident Rise (125%) 4. Efficiency and financial strength: ROACE (12.5%) and Net Debt/EBITDA (12.5%) 2024 targets MSRs: Business and individual targets set on the basis of those assigned to the CEO/GM and the responsibilities assigned to them. Assessment · Performance scale: 70-150 points (target - 100; below 70 points the result is calculated as zero); · Minimum incentive threshold. 85 total performance points, · Possible application to the performance soxe of an adjustment or 1.1 for operations and/or results of particular stratego. significance (with a maximum score of no more than 150 points) or of 0.9 for adverse seenarios and extrearching negative economic financial results (with a minimum score of no less than 85 points).
INCENTIVE CRITERIA AND LEVELS	CEO incentive level · Incentive base: 150% of fixed remumeration; · Vested incentive between 80% and 150% of incentive base, with an innual portion (65%) and deferred a portion (35%) autyce to three-year results and distructed in a variable amount personal 28% and 230% of the awarded postion. · Annual amount payable: · threshold of 83% of fixed remuneration; · target of 98% of fixed remuneration, · max 746% of fixed remuneration, · Payable deferred portion; - tureshold of 38% of tixed remineration, - target of 68% of fixed remuneration; - max. 181% of fixed remuneration. MSRs incentive level · Incentive base: up to a maximum of 100% of twed remiuneration; · Annual amount payable: up to a maximum of 98% of fixed remumeration; · Payable deferred portion: up to a maximum of 121% of fixed remuneration;
	LONG-TERM EQUITY-BASED INCENTIVE PLAN 2023-2025
PURPOSE AND CONDITIONS	Encourage long-term value creation for shareholders and sustainability The Flan is subject to malus/clawback conditions and 50% of the shares pranted are restricted for the grant date; for the CEO(GM, this is equivalent, in the event of shares granted annually equal to the UT awarded, to a shareholding objective, achievable withn 2 years, of an value equal to 1 5 times the foced remuneration.
CRITERIA AND PARAMETERS Continues	No. of shares awarded Determined by the rate between the more of the award, calculated as the oversion of the daily mose recorded in the four months before the month in which the Board approves the award. Three-year targets 1} 25% Market Target: linked to Total Shareholder Return (relative); 2) 40% Economic and Financial Target: Organic Free Cash Flow (absolute); 3) 35% Environmental Sustainability and Energy Transcion Targets (absolute), structured as follows: 3 1) 10% Decartionisation Target. upstream net GHG emissions Scope 1 and Scope 2 equity; 3.2) 15% Energy Transfirm Objective: electricity generation program from renewables and production. 3.31 10% Circular Economy Target: vertical integration of agribusiness:

SECTION I

ANNEX

[continued]

CRITERIA AND PARAMETERS	Performance measurement over a 3-year period · Relative parameters: measured aparist the Peer Group of six European energy companies (Shell, Totalinerores, BP Repsol, Egunor and OMV). · Absolute parameters: (FCF, Decarbonsation and Croular economy): measured against targets see in the Stratego Plan. No. of shares granted at the end of the vesting penod Determined as a function of performance over Syears and pier between 40% (theshold) and 180% (maxmum) of the rumber of awarded shares.
INCENTIVE LEVEL	CEO: · Value of awarded shares; up to a max amount equal to 150% of total fived remuneration. · Value of granted shares: threshold of 60% of fixed remuneration. - target of 183.75% of fixed remuneration; max. 270% of fixed remuneration. MSRs: - Value of awarded shares: depending on the level of the role, up to 75% of fixed remuneration. · Value of granted shares: depending on the level of the role, up to 135% of fixed remuneration. N.B: the monetary values are net of the impact of any changes in the stock price.
	EMPLOYEE STOCK OWNERSHIP PLAN 2024-2026
PURPOSE	Strengthen Eni people's sense of belonging to the company and participation in the growth of corporate value, in line with the interests of shareholders, as well as to support their purchase power.
CRITERIA AND PARAMETERS	The Pan calls for three annual grants in the pencipal for the two year occiod 2024 2025 two free grants of Eni shares for an individual monatory value of £2,000, while for 2026 a "co- investment" which provides upon the purchase of the employee; the grant of the company according to a matching sharemechanism of 50% up to a maximum.of 1.000 curos The shares will be subject to lock-up restrictions (theres granted free of charge, annual for any shares purchased by employees)

For the Chief Evecutive Officer and General Managers with Stretegic with Stretegic Responsibilited and Executives participating in the LTI Equity-Based Plan, the grant is limited to 1 symbolic share

• For more detailed information, including the cost and share capital, please see the liftermation Document for the Plan®.
• OTHER TREATMENTS

NON-MONETARY BENEFITS PURPOSE Retain managers in the Company CRITERIA Benefts, mainly insurance and welfare related, defined in national collective bargaining agreement and in supplementary company level agreements for Executives (including GM and MSRs) · Supplementary pension scheme: · Supplementary healthcare scheme; · Insurance · Car for business and personal use. PAYMENTS DUE IN THE EVENT OF TERMINATION OF OFFICE OR EMPLOYMENT PURPOSE Protect the Company from potential litigation and/or competitive risks associated with terminations without just cause. TERMINATION CEO: For the role of CEO: equal to two years of fine with Recommendation 2009/385/EC) in the case of early termination INDEMNITY of a term or non renewal, as well as resignation justified by a reduction of delegated powers. For the role of General Manager Indennity in the case of consensual termination equal to two years of fixed and short-term remuneration, within the limits of the protections established in the collective bargaining agreement® (CONL). Indermities are not due in the event of diamissal for "just cause" and resignation not justified by a reduction of delegated powers MSRs: For Managers with Strategic Responsibilities, as for all Eril executives, there are various treatments agreed upon individually based on citteria established by Eni for cases of retirement incentives which take into account the role held and performance, within the limits of the protections established in the same CCNL 3 which call for, in the case of terminations without just cause, a maximum of three years of total actual remuneration, including the notice. NON-COMPETE CEO: The continuation of the nor-compete agreement already activated by the Board of Directors on March 14, 2019 AGREEMENT Agreement Requirements · validity 18 months, · nor-compete constraints: for the Oil & Gas sector these include 19 countries, updated to also include companies in the Creuiar Economy soctor. Agreement Payment · fixed companent €1.8 million, · vanable component. determined as a function of the average of results for the STI Plan in the previous three years, between €500,000 (performance target) and €1,000,000 (maximum performance). MSRs: Orly for cases of terrination presenting high-competitive risks relating to the nature of the position; payment based on current remuneration levels and the extension of period and commitments undertaken

(i) Peparadopersuarite (in 14 bs of Logistere Sed February 24, 198 and Article A to the Creation (results) (results) (results) (results) (results) (results) (results) (result Remuneration' section in compliance with current regulations. thin the be your cases coll, practions and to up to e nearing of the only of the only of the creating (field remaines to walles), noutrons and trop your and trop your and tro

notice indermity, consistent with national regulations (Article 2121, Unif Code).

RESULTS OF THE SHAREHOLDERS' VOTE

The Shareholders' Meeting of May 10, 2023, in accordance with the provisions of applicable regulation, approved the Remuneration Policy for the 2023-2026 term. The percentage of participants voting in favour was 92.64%, while the subset of institutional investors voting in favour came to 85.80%. The average approval rate of Eni's Remuneration Policy therefore remains at around 90% for both categories.

Sec. 1-2017-2023 Shareholders' Meeting vote on the Policy

CHART 6 - RESULTS OF SHAREHOLDERS' VOTE ON ENI REMUNERATION REPORT IN 2017-2023 - SECTION I

INSTITUTIONAL INVESTORS (% voting)

As regards the non-binding shareholders' vote on the section of the Report at the Shareholders' Meeting on May 10, 2023, the percentage of participants voting in favour carne to 78.33%, while the subset of institutional investors voting in favour was 58.18%,

TOTAL SHAREHOLDERS (% voting)

CHART 7 - RESULTS OF SHAREHOLDERS' VOTE ON ENI REMUNERATION REPORT IN 2020-2023 - SECTION II

Sec. II - Shareholders' vote on the Implementation of the Policy 2020-2023

ANNEX

INSTITUTIONAL INVESTORS (% voting)

The votes achieved highlight the efficacy of the Remuneration Policy in supporting the corporate strategy and the use of constant and open dialogue with the market.

Section I 2024 Remuneration Policy

This Section will be subject to a binding vote during the Shareholders' Meeting of May 15, 2024, according to the provisions of applicable legislation. The Policy described in this section has a one-year duration.

MAIN CHANGES IN THE POLICY

The 2024 Remuneration Policy for Directors, Auditors, Chief Operating Officers and Other Managers with Strategic Responsibilities was approved by the Board of Directors on April 4, 2024 and, keeping remuneration levels unchanged with respect to the previous policy, has one substantial innovation which is the introduction of a Employee Stock Ownership Plan for all Eni employees, with the aim of strengthening their sense of belonging to the company and participation in the growth of corporate value, in line with the interests of shareholders, as well as to support their purchase power. For the Chief Executive Officer, the Chief Operating Officers, Managers with Strategic Responsibilities and Executives involved in the LTI equity based Plan, grant has a purely symbolic value, as better described in the dedicated section. Additionally, the Clawback Regulation was updated, using the terms requested in the recent SEC/NYSE regulation, for cases of "accounting restatement".

CORPORATE GOVERNANCE

Bodies and parties involved

The Remuneration Policy of members of the Eni Board of Directors, Board of Statutory Auditors, as well as Chief Operating Officers and Managers with Strategic Responsibilities, is defined in accordance with the provisions of law and the By laws, according to which:

• · the Shareholders' Meeting delemines the remuneration of the Chairman and other members of the Board of Directors, as well as the remuneration of the members of the Board of Statutory Auditors, at the time they are appointed and for the entire duration of their term (Art. 2389 (1) of the Italian Civil Code and Art. 26 of Eni By-Laws, Art. 2402 of the Italian Civil Code),
• · the Board of Directors determines the remuneration of the Directors with delegated powers and of those who participate in Board Committees, after examining the opinion of the Board of Statutory Auditors (Art. 2389 (3) of the Italian Civil Code).

In line with Eni's corporate governance system'3, the Board is responsible for:

• · approving the Remuneration Policy described in the first section for members of the Board of Statutory Auditors and Managers with Strategic Responsibilities;
• · defining the Company's targets and approving the Company's performance thereby determining the variable remuneration of eligible Directors with delegated powers;
• subject to a proposal of the Chairman in agreement with the Chief Executive Officer, defining the remuneration structure of the Group Head of Internal Audit in accordance with the remuneration policies of the Company on receipt of a favourable opinion from the Control and Risk Committee. and having examined the opinion of the Board of Statutory Auditors.

(13) For more information regarding the Eni corporate governance system, please refer to the "Corporate Governance and Shareholdings Structure Report" published in the "Corporate Governance" section of the Company website

Compliance of Policy with provisions of law and By-laws

Employee Stock

Ownership Plan

ANNEX

In line with the recommendations of the Italian Governance Code, the Board of Directors is supported. by a Committee of independent Non-Executive Directors (the Remuneration Committee) which makes proposals and provides advice on all remuneration issues.

The Remuneration Policy is approved by the Board, acting on a proposal of the Remuneration Committee, and is examined by the Shareholders' Meeting, which is called to express a binding vote on the matter with the frequency required by the duration of the Policy, and in any case at least every three years or in the event of changes.

The Board of Directors 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 circumstances relevant to its implementation (Principle XVII of the Governance Code).

The Shareholders' Meeting is required to express an advisory vote on the second section of the Report. devoted to remuneration paid during the year to Directors, Statutory Auditors, Chief Operating Officers and, in aggregate, Managers with Strategic Responsibilities,

Engagement on Remuneration Policy

At Eni, we develop interaction with our shareholders and institutional investors regarding remuneration policies, since we are aware of the importance of involving shareholders in the process of defining and monitoring the actual implementation of the Remuneration Policy for Directors and Managers with Strategic Responsibilities, also as recognised by lawmakers when transposing the guidelines contained in the SRD II.

Eni offers it shareholders and investors a number of tools and channels for communication: periodic meetings and conference calls and the publication of detailed and complete information on its website ("Remuneration" section14 on the "Governance" page),

In particular, an annual Engagement Plan is established, with the main institutional investors and proxy advisors, to help with proposals of Policies to submit for approval at the Shareholders' Meetings, in line with the Policy for Managing Dialogue with Investors, approved by the Board of Directors. In the context of the Engagement Plan, two cycles of meetings are envisaged, in the autumn and spring, with the participation of the Remuneration Committee, highlighting the importance of direct communication with the market on the issues the Committee is responsible for, within the terms of the Policy for Managing Dialogue with Investors. The Committee examines and monitors the results of engagement activities, in line with the Policy for Managing Dialogue with Investors, ensuring the Board of Directors is adequately informed on developments with reference to dialogue on remuneration issues.

Eni Remuneration Committee

Composition, appointments and tasks

The Eni Remuneration Committee was first established by the Board of Directors in 1996. Its Composition and role composition and appointment, remit and operations, in line with the recommendations of the Governance Code, are governed by specific Rules approved by the Board of Directors and published on the Company website15

of the Remuneration Committee

(14) https://www.eni.com/R_IT/azienda/governance/remunerazione page.

(15) The rulea of the Remuneration Committee are available in the "Corporate Governance" section of the Company's website

Adoption of an Engagement Plan

Tasks of the Remuneration Committee

The Committee is composed of three Non-Executive Directors, all of whom meet the definition of independence as set out in Italian law and the Italian Governance Code and all possessing adequate knowledge and experience of financial matters or remuneration policies, as assessed by the Board at the time of their appointment, as recommended (for at least one member of the Committee) by the Italian Governance Code™ (Recommendation no. 26). Below are details of the composition and meetings of Committee in 2023.

The Head of Human Capital & Procurement Coordination of Eni acts as Secretary to the Committee, with the help of the Head of Compensation & Benefits, assists the Committee and its Chairwoman in the performance of their activities.

The Committee assists the Board of Directors with preparatory, consultative and advisory functions in accordance with the By-laws and the Corporate Governance Code (Principle XVI and Recommendation no. 25, letters a), b), c) and d):

• · 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;
• 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:
• · presents proposals and expresses opinions for the remuneration of members of the Board's internal committees
• · having examined the Chief Executive Officer's indications, presents proposals for general criteria for the remuneration of Managers with Strategic Responsibilities; annual and Long Term Incentive Plans, including equity based plans; establishing performance targets and assessing performance against them, in connection with the determination of the variable portion of the remuneration for Directors with delegated powers and with the implementation of the approved incentive plans;
• periodically evaluates the adequacy, overall consistency and actual implementation of the adopted Policy and assesses, in particular, the actual achievement of performance objectives, formulating proposals on the matter to the Board;
• · examines and monitors the results of the engagement activities carried out in support of Eni Remuneration Policy, within the terms set forth in the engagement policy approved by the Board.

In addition to performing its functions, the Committee shall deliver opinions on any remuneration transactions eventually required by the current Company procedure in respect of transactions with related parties17, within the conditions laid down in the same procedure.

The Committee reports at the first available meeting of the Board of Directors on the most significant issues addressed by the Committee during the meetings. It also reports to the Board on its activities at least every six months and no later than the time limit for the approval of the Annual Report and the Interim Report, at the Board meeting designated by the Chairman of the Board of Directors.

Operating procedures

The Committee meets as often as necessary to fulfil its functions, as foreseen in its Rules, usually on the dates established in the annual meeting schedule approved by the Committee itself, and in the presence of at least the majority of its current members. The Chairman of the Committee calls and chairs the meetings; in case of absence or impediment, the meeting is chaired by the oldest attending member. The Committee decides with an absolute majority of those present.

(16) See press release of May 11, 2023 available on the Company website.

(17) With reference to the "Transactions with interests of Directors and transactions with related parties' policy, adopted for the first time, in impiementation of the Conson regulations, on November 18, 2010. For more information see the 2023 Corporate Governance and Sharehoidings Structure Report, available on the Company's website

ANNEX

The Committee Secretary, who may be assisted in this function by staff of Human Capital & Procurement Coordination, produces the minutes of the meetings.

Members of the Board of Statutory Auditors and the Magistrate of the Court of Auditors may attend the Committee 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; as well as other Directors, after having heard the Chairman of the Board. No Director and, in particular, no Director with delegated powers, may take part in meetings of the Committee during which Board proposals regarding their remuneration are being discussed (Recommendation no. 26), unless the proposals regard all the members of the Committees established within the Board of Directors. 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 compelence, may be invited to participate in the meeting on specific items of the agenda. The provisions applicable to the composition of the Committee shall remain applicable where the Committee is called upon to perform the duties required under the procedure for related party transactions adopted by the Company.

The Committee has the right to access information and Company functions as necessary to perform Its duties, and to make use of external independent consultants, within the terms of the Rules and the limits of the budget set by the Board of Directors (Recommendation no. 17).

Activities performed in 2023 and planned for 2024

In 2023, the Remuneration Committee met a total of 10 times, with an average attendance of 100% of Its members and an average duration of 1 hour and 52 minutes. The documentation supporting the meetings was sent to the members of the Committee within the deadlines set by the Rules

TABLE 8 - REMUNERATION COMMITTEE MEETINGS IN 2023

Committee in office until May 10, 2023
Nathalie Tocci (Chairwoman)	4 meetings in 2023
Karina Litvack	Average duration:
Raphael Vermeir	1 h and 55 minutes

Committee in office from May 11, 2023/41

Massimo Belcredital (Chairman)	6 meetings in 2023
Cristina Sgubin	Average duration:
Raphael Vermeir®)	1 h and 50 minutes

(if Corposition following reveal of party of Dressons' decision of May 11, 2003-ss announce in the press relose of the same darf (b) Directors Befored: and Vermeir have been appointed from the minority slate:

At least one member of the Board of Statutory Auditors participated in all Committee meetings. At the invitation of the Chairman of the Committee, Executives of the Company and advisors participated in specific meetings, to provide information and clanfications requested by the Committee to pursue the analysis conducted,

The Committee scheduled seven meetings for 2024, three of which had already been held as of the date of approval of this Report. The main activities pursued by the Committee in the year are shown below, with an indication of the main initiatives planned for this year, in line with its annual activity plan.

TABLE 9 - ANNUAL CYCLE OF REMUNERATION COMMITTEE ACTIVITIES

1ª HALF MULADY-JUNE

POLICY ESTABLISHMENT AND IMPLEMENTATION

• Periodic assessment of the Policy adopted in the previous year using remuneration comparative studies.
• · Policy establishment and preparation of the Remuneration Report.
• · Verification and implementation of the existing STI Plan.
• Definition of the targets related to the Variable Incentive Plans.
• · Verification of the existing LTI Plan.

ENGAGEMENT

• · Analysis of institutional investor and proxy advisors voting policies.
• · 2nd round of meetings with institutional investors and proxy advisors and examination of engagement results.
• Examination of voting recommendations of proxy advisors and voting projections.

2nd HALF JULY-DECEMBER

POLICY ESTABLISHMENT AND IMPLEMENTATION

• · Implementation of the existing LTI Plan
• · Monitoring of the requiatory framework and governance and reporting practices in relation to remuneration.

ENGAGEMENT

• · Examination of Shareholders' Meeting votes on remuneration issues and comparison with peers.
• · Definition of the Annual Engagement Plan.
• · 121 round of meetings with institutional investors and proxy advisors and examination of engagement results.

POLICY ESTABLISHMENT AND IMPLEMENTATION

In the first half of 2023, in implementations of the Governance Code, the Conmittee conducted its periodic review of the adequiacy overall consistency and actual implementation Poloy in 2022, also to identity guideine propesals for the Policy for 2023-2026. In particular, it verified the remoneration belegated Powers, for Non-Executive Directors for participation on Board Committees, for members of the Board of Statutory Auditors and Other Managers with Strategic Responsibilities

The Committee also examined, during multiple meeting the new Long Term Equity-Based Incentive Plan for 2023-2025 and the Report on the 2023-2026 Remuneration Pard Remuneration Pard 2022. These proposals were approved by the Board on March 16, 2023 and submitted to the Shareholders' Meeting for a vote on May 10, 2023.

During the same period, the Committee verlied the annual results for 2022 for the purposes of implementing the Short-Term Incentive Plan for the Chief Executive Officer and General Manager and defined the 2023 performance targets for the Variable Incentive Plans.

Following the renewal of the company bodies, "induction" activities were carried out to inform the new Dreators about the cycle of activity for the Remuneration Committee, as well as the principles, structure and remuneration levels established in the Eni Remuneration Policy, in line with the approved Policy, the Committee was called on to formalise proposals on the remuneration of Directors with Delegated Powers for the new 2028-2026 term, and to define fees for non-Executive Directors for participation on Board Committed to and approved by the Board of Directors on June 1ª

In the second half of 2023, the Committee prepared the 2023 irripiementation of the LT Equity-Based Plan 2023-2025 for the Chief Executive Officer and General Management personnel for business, preparing the relative Regulations. The Committee also updated the "Clawback implementation Criteria" regulation, as called for in the Eni Remuneration Policy, to bring it into line with the terms requested in the recent SEC/N/SE regulations. The Committee also examined and approved the update to the note on methodology with reference to neutralising external variables when venlying results, in relation to the consolidation of the new business model.

Finally the Committee began preliminary activities to prepare the Employee Stock Ownership Plan for all employees, to be implemented starting in 2024.

ENGAGEMENT

In the first half of 2023, the Committee Chairman, as part of the second engagement round, had numerous meetings with the main institutional investors (representing over 13% of share captal) and proxy advisors, to maintain continuous dialogue with reference to the Remuneration Policy and implementation of the same.

The Committee examined the voting recommendations issued by the leading proxy advisors and the voting projections prepart of leading consuiting firms.

Following the renewal of the company bodies, "Industion" activities were carried out for the new Drectors with reference to the engagement process and activities with the main proxy advisors and institutional investors.

During the second hall of 2023, the Committee aralysed the vith those of national and European pees, as well as defining the annual engagement plan in view of the upcoming 2024 Shareholders' Meetings, held in July, October and November, included top investors representing around 12% of Eni share captal, as well as the main proxy advisors, in order to introduce the new Remaneration Committee, cotain feedback on the 2023 votes and receive advance notice about voting policies for 2024 if relevant. LETTER INTRODUCTION: EXECUTIVE SUMMARY

25

2024 Remuneration Policy approval process

in the exercise of its powers, the Remuneration Committee defined the structure and contents of the Remuneration Policy, for the purpose of preparing this Report, specifically at the meetings held on January 22, February 19 and March 4, 2024, in accordance with the recommendations of the Governance Code. In taking its decisions, the Committee reviewed the appropriateness, overall consistency and effective implementation of the 2023 Policy.

For the purpose of preparing the Policy, the results of the monitoring of the legislative framework and governance practices on executive remuneration were assessed, with particular regard to developments in the quidelines of institutional investors and feedback received during the engagement meetings held.

Lastly, the Committee considered comparative remuneration studies prepared by major international consultants (Willis Towers Watson and Korn Ferry).

The 2024 Eni Remuneration Policy for Directors, Auditors and other Managers with Strategic Responsibilities was approved by the Board of Directors, acting on a proposal of the Remuneration Committee, at its meeting of April 4, 2024, at the same time as the approval of this Report.

The 2024 Policy does not allow for exceptions in the implementation phase. Any future revision needs will therefore be submitted by the Board, acting on a proposal of the Remuneration Committee, for approval by the Shareholders' Meeting. The implementation policies approved by the shareholders is carried out by corporate bodies delegated to do so, with the support of the competent. corporate functions.

PURPOSE AND GENERAL PRINCIPLES OF THE REMUNERATION POLICY

Purpose

The Eni Remuneration Policy contributes to achieving the Company's strategies, with incentive structures tied to financial, business, environmental and/or social sustainability and energy transition goals, taking a long-term view, taking into account the interests of all stakeholders.

Enl's Remuneration Policy is also consistent with the governance model adopted by the Company and the recommendations of the Corporate Governance Code, in particular providing that the remuneration. of Directors, Chief Operating Officers and Managers with Strategic Responsibilities is functional to the pursuit of the sustainable success of the Company and reflects the need to have, retain and motivate people with the skills and professionalism deemed suitable for the role assigned (Principle XV of the Governance Code).

Remuneration of members of the Board of Statutory Auditors, illustrated below, was determined. pursuant to Article 2402, Civil Code, by the Eni Shareholders' Meeting on 10 May 2023.

Eni's Remuneration Policy also contributes to achieving the Company's mission, by:

• · promoting actions and behaviours reflecting the Company's values and culture, consistent with the principles of plurality, equal opportunity, enhancement of individuals' knowledge and skills, fairness, integrity and non-discrimination, as described in the Code of Ethics 18 and Eni Policy Tour people"10, in line with the objectives of the United Nations and according to the principle of "equal pay for equal work ;
• · recognising roles and responsibilities, results, and the quality of professional contribution, utilising fair and competitive market references able to support a decent standard of living, higher than the legal or contractual minimums in force, as well as the minimum wages of local markets.

(18) For more information on the Code of Ethics, piease refer to the Corporate Governance and Shareholdings Structure Report 2023, available on the Corporate Governance website (19) Policy approved by the Board of Directors on July 28, 2010.

Policy consistent with recommendations of the Governance Code

No exception envisaged

Connection with the Company's strategies

Consistency with recommendations of the Governance Code

General principles

In pursuing the above, the remuneration of Directors and key executives is defined in line with the following principles and criteria:

Remuneration of managerial roles, CEO/GM and MSRs

Total remuneration packages aim for consistency with standard market values applicable for positions or roles of similar level of responsibility and complexity, based on panels of national and international companies comparable to Eni, developed through benchmarking analysis carried out by international remuneration advisors (Recommendation no. 25),

Adjusted balance between fixed and variable remuneration

Consistency with

market benchmark

The remuneration package is appropriately balanced between a fixed and a variable component, in relation to the strategic objectives and the risk management policy of the Company Recommendation no. 27, letter a). Executive roles with the greatest influence on business performance are characterised by variable remuneration containing a significant percentage of incentive components, particularly long-term awards (Recommendation no. 27, letter a), while the vesting period and/or incentive deferral period are defined over a period of at least three years (Recommendation no. 27, letter d),

Remuneration Structure

Fixed Remuneration and Benefits

Fixed component and non-monetary benefits congruent with respect to the delegated powers and/ or responsibilities assigned, as well as the experience and skills of the individual in question and market benchmarks with reference to the panel of comparable companies. More specifically, benefits privilege components intended to provide social security and healthcare insurance.

The variable component is defined within maximum limits (Recommendation no. 27, letter b) and is intended to anchor remuneration to the strategy and results effectively achieved over the short and

Variable remuneration.

Severance indemnities and non-compete agreements

Financial and

non-financial targets

Additional payments that be awarded upon termination of employment and/or term of office for executive roles, as well as non-compete agreements that may apply to roles at greater risk of "poaching", are defined in terms of either a maximum amount or number of years of remuneration, in line with the remuneration received and the performance achieved (Recommendation no. 27, (etter f), and in compliance with the protections set out in collective bargaining agreements (CCNL) for executives.

Variable incentive systems

long-term, as well as to the interests of stakeholders,

Short and long-term variable remuneration, linked to pre-established and measurable financial and non-financial targets, consistent with the Strategic Plan and the expectations of shareholders and other stakeholders, intended to combine operational, economic and financial solidity with social and environmental sustainability (Principle XV and Recommendation no. 27, letter c), These targets are defined so as to ensure.

• · annual performance assessment, on the basis of a balanced scorecard that values the overall business and individual performance, defined in relation to targets specific to each area of responsibility, and for those in charge of internal audit responsibilities, in line with their specific assigned role;
• · measurement of long-term results both in absolute terms, with reference to the sustainable capacity to generate profit, and in relative terms with respect to the Peer Group, with reference to the capacity to create value with respect to main competitors.

Equity-based Long-term equity-based incentive plans intended to strengthen alignment with shareholder remuneration plans expectations and featuring: three-year vesting periods, pre-established and measurable targets, portion of shares granted locked up for a 2 year period (Recommendation no. 28).

Verification of results Variable remuneration paid pursuant to a detailed verification process that assesses actual performance against the originally assigned targets, if necessary adjusted to neutralise the effects LETTER INTRODUCTION: EXECUTIVE SUMMARY

of exogenous variables such as the commodity price scenario and exchange rate, as well as events which by their nature are not attributable to management performance, based on the adjustment analysis methodology approved by the Remuneration Committee.

In the case that incentives (or the right to the same) have been achieved based on data which is later found to be clearly erroneous (Recommendation no. 27, letter e), or in cases of wilful alteration of the same, a specific malus/clawback Regulation applies, approved by the Board of Directors based on a proposal from the Remuneration Committee, which allows for non-payment and/or assignment of incentives for which the right to receive has already been vested or is currently in the process of vesting (malus), or the return of all or part of the incentives paid and/or granted (clawback)

The Policy provides that the activation of recoupment claims (or withdrawal of incentives awarded but not yet paid) must take place, once appropriate verification has been completed, within three years of payment (or award) in cases of error, and within five years in cases of deliberate intent to defraud.

The Regulation can also be applied in cases of termination for disciplinary reasons, including serious and intentional violations of law and/or regulations, the Code of Ethics or Company rules, without prejudice to any action allowed under law for the protection of the Company's interests.

The Regulation has been updated, using the terms requested in the recent SEC/NYSE regulation, for cases of "accounting restatement".

Remuneration of the Chairman and Non-Executive Directors

Remuneration of Non Executive Directors is commensurate with competence, professional qualification and effort required for the 1asks assigned and participation on Board Committees set up in accordance with the By-laws (Recommendation no. 29), taking account of relevant market benchmarks, also considering comparable overseas experience, appropriate differentiation between the remaneration afforded to Committee Chairmen, and that of other Committee Members, considering the different roles respectively held regardination of work and relationships with Corporate bodies and managerial teams; Non-Executive Directors are not beneficiaties of variable incentive plans, including equity-based ones, unless decided otherwise by the Shareholders' Meeting.

Remuneration of Members of the Board of Statutory Auditors

Fees for members of the Board of Statutory Auditors were determined by the Shareholders' Meeting on May 10, 2023, based on a proposal prepared by the shareholder of reference, which was based on the fees applied by publicly owned issuers with high capitalisation. In consideration of the role played by the Chairman in coordinating the work and in cooperating with corporate bodies and company departments, a moderate increase was envisaged with respect to the remuneration of the other members.

2024 REMUNERATION POLICY

Connection with the Company's strategies

Through its short and long-term incentive systems, the Remuneration Policy supports the realization of the Company's Strategic Plan, through the definition of targets able to promote the creation of sustainable value for shareholders and other stakeholders in the medium/long-term. In particular, management's actions are assessed:

· in a short-term horizon, in relation to a comprehensive and balanced framework of complementary targets, aimed at ensuring the profitability of the Company as a whole and operational efficiency, the implementation of the energy transition and decarbonisation path, through the incremental installed capacity relating to renewable sources and the reduction of net Upstream GHG emissions Scope 1 and Scope 2 equity, human safety as well as financial strength;

Clawback and malus clauses

Short-term goals

27

Long-term goals

· in a medium/long-term horizon, with reference to equity-based performance (TSR) directly connected to shareholder interests, and in relation to a series of targeted results in absolute terms and characterised by the centrality of the economic/financial performance (organic Free Cash Flow), integrated by a significant focus on the strategic topics of decarbonisation, energy transition and circular economy.

Market benchmarks and remuneration Peer Group

For the Chief Executive Officer, the remuneration is assessed against the median value of the remuneration of CEOs of a remuneration Peer Group formed of 18 European companies operating in En's benchmark sectors, taking account of the energy transition process and business transformation strategies. In particular, the companies of the remuneration Peer Group were selected from the energy, utilities and other industrial sectors; comparable with Eni in relation to the business portfolio and/or the organisational size and business complexity.

		Business activities
Company	Country	Energy	Utility	Chemical	Mining	Other
1 Shell	нкуNE	4
2 TotalEnergies	France	1
3 BB	પ્રદ	ಳ
4 Repsol	Spain	1
5 Equiner	Norway	র্ব
6 OMV Group	Austria	ಳ
7 : RANF	Germany		1
8 Iberdrola	Spain		1
9 CON	Germany		1
10 ENGIE	France		41
11 Enel	liary		7
12 BASF	Germany			1
13 . Blayer	Germany			ಳ
14 Rio Tinto	ામ				1
15 Anglo American	UK				ﻟﻬ
16 Volkswagen	Germany					4
17 Vodafone.	ਿੱਕ					1
18 Sierrieris	Germany					ﻬﺎ

TABLE 10 - NEW CEO REMUNERATION PEER GROUP

For the Chairman and the Non-Executive Directors, the positioning of remuneration is assessed by comparing similar roles in the Top Italy Peer Group, which is composed of the main companies listed on the FTSE MIB (Assicurazioni Generali; Atlantia, Enel, Intesa Sanpaolo, Leonardo, Mediaset, Mediobanca, Poste Italiane, Prysmian, Snam, Terna, TIM, Unicredit).

For Managers with Strategic Responsibilities, the positioning of remuneration is assessed by companing roles of the same level of managerial complexity and responsibility within industrial corporations in national and international markets.

Comparisons of remuneration have been conducted with the help of the advisory firms Willis Towers Watson, and Korn Ferry.

Employee remuneration and working conditions

Eni places its people at the heart of its business strategy and is constantly committed to promoting. working conditions in line with the United Nations objectives of wage improvement, reduction of income inequality, promotion of decent job opportunities, generational, ethnic equality etc. according to the "equal pay for equal work" principle.

In particular, Eni applies a global integrated remuneration system to all its people, consistent with the reference markets and linked to company and individual performance, in compliance with local legislation. This system adopts remuneration references made up by the market median, guaranteeing fair and competitive remuneration with respect to the role and professional skills and always able to support a decent standard of living, higher than the mere subsistence levels and/or the legal or contractual minimums in force, as well as the market minimum wages, as highlighted by the indicators represented in the Summary

Eni also pays particular attention to the safety, well-being and quality of life of its people, as driving factors for the healthy growth of the Company. This is reflected in Eni's ongoing commitment in the field of Welfare and in a wide offer of benefits and services in different areas: from health protection to social security coverage, from work and private life balance to training.

Employee Stock Ownership Plan 2024-2026

Implementation of a Employee Stock Ownership Plan (ESOP) is planned to begin in 2024, intended for all Eni employees with the aim of strengthening their sense of belonging to the company and participation in the growth of corporate value, in the interests of shareholders, as well as to support their purchase power.

The Plan calls for three annual grants in the period 2024-2026 and, in particular, for the two-year period 2024-2025 two free grants of Eni shares for an individual monetary value of €2,000, while for 2026 a "co- investment" which provides, upon the purchase of Eni shares by the employee, the grant of free shares by the company, according to a matching share mechanism of 50% up to a maximum of 1,000 euros.

The shares will be subject to lock-up restrictions (three years for shares granted free of charge, annual for any shares purchased by employees)

For the Chief Executive Officer and General Manager, Chief Operating Officers and Managers with Strategic Responsibilities and Executives participating in the LTI Equity-Based Plan, the grant is limited to 1 symbolic share.

The Plan, approved by the Board of Directors on April 4, 2024, will be submitted for approval to the Shareholders' Meeting called for May 15, 2024

For more details about the Plan, including the cost and amount of share capital, please see the Information Document prepared in line with Article 114-bis of Italian Legislative Decree 58 of February 24, 1998 and Article 84-bis of the Regulation adopted by Consob with resolution 11971 of May 14, 1999, as subsequently modified and supplemented (Issuers Regulation), published on the Company's website in the "Governance/Remuneration" section and made available to the public in line with current law.

"Equal pay for equal work" principle

A worldwide integrated remuneration system

OFFICERS COVERED BY THE POLICY

Chairman of the Board of Directors

The 2024 Remuneration Policy for the Chairman establishes, in consideration of the qualifications of the designated person and the findings for remuneration benchmarks, total fixed remuneration of €500,000 gross, unchanged with respect to the previous term, including the remuneration for the role determined by the Shareholders' Meeting of May 10, 2023 (€90,000 gross) and compensation for the delegated powers (€410,000 gross), approved by the Board of Directors on June 1, 2023.

There is also a health and insurance coverage against permanent disability due to injury or illness contracted in the workplace or elsewhere.

No specific severance payments are provided for the Chairman, nor do any agreements exist for indemnities in the case of resignation or early termination of office20.

Non-executive Directors

The 2024 Remuneration Policy for non-executive and/or independent Directors establishes, taking into account the findings for remuneration benchmarks, as well as the skills and experience required to carry out the positions, the following annual remuneration for participation on Board Committees, as approved by the Board of Directors on June 1, 2023 and unchanged with respect to the previous term:

• · for the Control and Risk Committee, remuneration of €70,000 for the Chairman and €50,000 for other members.
• · for the Remuneration Committee, remuneration of €50,000 for the Chairman and €35,000 for other members:
• · for the Sustainability and Scenarios Committee, remuneration of €50,000 for the Chairman and €35,000 for other members;
• · for the Appointments Committee, remuneration of €40,000 for the Chairman and £30,000 for other members.

These arrounts supplement the remuneration established by the Shareholders' Meeting on May 10, 2023 for the remuneration of the Directors, equal to €80,000.

No specific severance payments are provided for Non-Executive Directors, nor do any agreements exist for indemnities in the case of resignation or early termination of office 21.

Board of Statutory Auditors

Regulations (Article 123-ter, Consolidated Law on Finance) establish that the first section of the Report must illustrate, clearly and understandably, the company's remuneration policy for Directors, Chief Operating Officers and Managers with Strategic Responsibilities as well as, without prejudice to that established in Article 2402 of the Civil Code, the members of the control body.

Article 2402, Civil Code establishes that annual remuneration of Statutory Auditors, if not established in the By-Laws, shall be determined by the Shareholders' Meeting at the time of appointment, effective for the entire duration of this subject, the Corporate Governance Code recommends that the remuneration be appropriate to the responsibilities, skills and commitment (no. meetings and average duration) required by the relevance of the position and the size and sector features of the company. Therefore, the relevance of the tasks carried out is considered, as well as applicable market references, taking into account the size and complexity of the Company,

(21) Information provided in accordance with Article 123-bis, paragraph 1, letter i), of the Consolidated Law on Financial Intermediation, an specified under the note above.

⁽²⁰⁾ in considention of the referral to this Report, in the 2023 Corporate Governance and Shareholdings Stucture Report, which is available in the Corporate Governance section of the Company's website, this information is being published in accordance with Article 123-bls, paragraph 1, letter (), of the Consolidated Law on Financial Internediation (agreements between companies and directors, members of the cantrol body or supervisory council which envisage indemnities in the event of resignation or discrissal without just cause, or if their empioyment contract should terminate as the result of a takeover bid)

In the Report on the Remuneration Policy, approved on March 16, 2023, the Board of Directors proposed, taking into account En's listing on the New York Stock Exchange, the evaluation of an increase in the remuneration for the 2023-2026 term. in relation to the increased professional commitments of the Board of Statutory Auditors, also in terms of activities carried out as the Audit Committee for the purposes of SEC compliance

Nonetheless, on May 10, 2023, the Shareholders' Meeting, based on a proposal from the reference shareholder, approved remuneration of €85,000 for the Chairman and of €75,000 for other members. of the Board of Statutory Auditors.

Chief Executive Officer and General Manager

Fixed remuneration

Total Fixed Remuneration (FR) is equal to €1,500,000, of which £600,000 for the position of Chief Executive Officer, which includes the remuneration of £80,000 gross annually for the position of Director approved by the Shareholders' Meeting on May 10, 2023 and €1,000,000 for the position of General Manager, This remuneration, approved by the Board of Directors on June 1, 2023, has been kept unchanged with respect to the previous term, keeping into account the continuity of the positions and relative delegated powers.

This remuneration encompasses any emoluments due for participation in the meetings of the boards of directors of other Eni subsidiaries and/or shareholdings.

In relation to the continued nature of the executive employment relationship, the position of CEO is also entitled to an allowance for travel, in line with the provisions of the relevant national collective bargaining agreement (CCNL) for executives of industrial companies and supplementary companylevel agreements.

Variable remuneration: short-term incentives with deferral

The Policy for 2024 term provides for the maintenance of a Short-Term Incentive Plan with deferral (STI Plan) with the same characteristics as the Plan envisaged in the 2020-2023 Remuneration Policy and unchanged with respect to the 2023-2026 policy approved the previous year.

PERFORMANCE CONDITIONS

The STI Plan provides for a structure of annual targets distributed across four clusters of equal weighting, consistent with the guidelines defined in the Strategic Plan and balanced against the interests of the various stakeholders.

In the Policy clusters, the Remuneration Committee proposes annually to the Board, the adoption of performance targets and parameters consistent with developments in company strategy from the perspective of medium/long-term sustainability. The value of each target is in line with the budgeted figure.

The 2024 annual targets approved by the BoD on March 13, 2024 at the proposal of the Remuneration Committee, in the context of the defined policy clusters, are shown in Table 11.

TABLE 11 - 2024 TARGETS FOR THE SHORT-TERM INCENTIVE PLAN WITH DEFERRAL 2025
------------------------------------------------------------------------------	--	--	--	--	--	--	--	--	--

ECONOMIC AND FINANCIAL RESULTS (25%)	OPERATING RESULTS (25%)	ENVIRONMENTAL SUSTAINABILITY AND HUMAN CAPITAL (25%)	EFFICIENCY AND FINANCIAL STRENGTH (25%)
INDICATORS · Earning Before Tax · Organic Free Cash Flow.	INDICATORS · Hydrocarbon production · Incremental installed renewable capacity	INDICATORS GHG net emissions upstieam Scope and 2 equity Seventy Incident Rate	INDICATORS · ROACE Net Debt/EBITDA
LEVERS · Traditional business value growth · Growth in new sectors	LEVERS · Fast track approach to project execution Organic and inorganic development of serewable energies	LEVERS Decartionisation HSE and sustainability	LEVERS · Financial discipline in investment projects · Efficiency of operating costs and G&A · Optimisation of working capital

	In particular:
Economic and financial targets	· the organic Earning Before Taxes (EBT) and Free Cash Flow (FCF) Indicators are measures of En's capacity to ensure the profitability of its businesses and ensure investments and shareholder remuneration are sustainable over time, even in particularly challenging situations. In this regard, Eni aims to accelerate the transformation strategy on one hand by increasing the reslience of traditional businesses and their ability to generate cash, and on the other by developing the energy transition businesses that are based on the integration of technologies, new business models and close collaboration with our stakeholders;
Operating objectives	· the indicators of hydrocarbon and incremental installed capacity of Renewables make it possible to join upstream business growth with renewable energy development targets connected to the decarbonisation strategy for operations and products;
Environmental sustainability and human capital objectives	· the Upstream GHG net emissions Scope 1 and 2 equity indicator (ICO,eq.) reflects Enis commitment to reducing GHG emissions, in line with the medium/long-term objectives that will lead the Company to decarbonise all products and processes by 2050. Eni aims to eliminate the carbon footprint associated with its activities, which also involves the gradual reduction of Scope 1 and Scope 2 Upstream emissions;
	· the Severity Incident Rate (SIR) Indicator reflect Enl's HSE priorities and the central importance of our commitment to individual safety. The prevention and risk minimization are cornerstones of Eni's operations in our commitment to achieving constant improvements in safety for all workers and to expressing this commitment in the process of assessing the performance of senior management. In particular, use of the SIR tocuses Enl's commitment on reducing serious injuries given that .it calculates the frequency of injuries over the number of hours worked, but weighted for the actual severity of the incident.
Efficiency and financial strength objectives	· the ROACE and debt-to-EBITDA inclicators measure the Company's financial discipline and the quality of our financial structure and earnings, which translates into a careful selection of investments, into efficiency and cost control, and into a rapid return on investment. All of these efforts enable us to reinforce our resiliency even during economic downturns,
Verification of results	Verification of objectives is done net of the effects of external variables (e.g. oil and gas prices, the Euro/dollar exchange rate), as well as events which by their nature cannot be attributed to management performance, based on the gap analysis method approved by the Remuneration Committee
	INCENTIVE MECHANISMS AND LEVELS
Incentive mechanisms and levels unchanged	In line with the general Remuneration Policy principles, the STI Plan with deferral features the same characteristics as in the previous term, described below. Each target is predetermined and measured based on a performance scale of 70-150 points (farget = 100) in relation to the weight assigned to each (a score below 70 points implies a performance multiplier of zero),
	For purposes of the total incentive award, the minimum overall performance is 85 points. In consideration of the need to promote initiatives for developing the business and to further align the remuneration of the CEO/GM with shareholder interests, the option of applying a coefficient of 1.1 to the total score of the annual performance record is also confirmed for operations of particular strategic importance not foreseen in the budget and/or extraordinarily positive annual economic/financial results (with a maximum score for the performance record of no more than 150 points). Also provided for, in a similar manner, is the option of applying a coefficient reducing the final score of 0.9 for adverse scenarios such as to determine extraordinarily negative annual economic/financial results (the performance record score may

not be less than 85 points),

These circumstances and any application and the corrective coefficient will be assessed by the Remuneration Committee, applying the criteria determined above and submitted for approval to the Board of Directors at the time Eni's annual performance is verified.

ANNEX

The Total Incentive (TI) is calculated using the following formula:

$$\mathbf{T} = \mathsf{FRR} \times \mathsf{L}_{\text{vaporator}} \times \mathsf{w}$$

Where FR is total fixed remuneration and "Incentive percentage at target performance level, set to 150% of total fixed remuneration for the Chief Executive Officer, and M is the multiplier related to the performance achieved, as shown in the chart below,

The total incentive is divided in:

1) an Annual portion (1) equal to 65% of the total incentive, paid in the year in which Annual incentive the performance was attained. The values of the Annual portion, depending on the performance achieved, are shown in the table below"2;

payable in the year

TABLE 12 - LEVELS OF ANNUAL PAYABLE INCENTIVE

Annual performance		<85 B5 threshold 100 target		150 max
Annual incentive (in % of Fixed Rem.)	0%	83%	98%	146%

2) a Deferred portion (1,3 equal to 35% of the total incentive subject to additional performance conditions in a three-year period, and payable in the year after said period, as shown in the chart below.

Deferred incentive subject to further performance conditions during a three-year vesting period

CHART 9 - DEFERRED INCENTIVE - TIMELINE

	PERFORMANCE AND VESTING PERIOD
YEAR T	YEAR T+1	YEAR T+2	YEAR T+3
Attribution of STI deferred portion			+ Payment of STI deferred portion

(22) The incentive values as a % of fixed remuneration shown in the table were calculated as follows
• Threshold: 83% = 65% x (150% x 85%)

· Target 98% = 65% x (150% x 100%)
· Max 146% = 65% x (150% x 150% x 150%)

The deferred portion payable (IDE) is determined as follows:

Ina = In X Mp

Where M, is the final multiplier given by the average of the annual multipliers determined on the basis of the performance achieved by Eni in each year of the three-year period, as shown in the chart below.

The values of the payable deferred incentive, depending on the performance achieved in the threeyear period, are shown in the table below23.

TABLE 13 - LEVELS OF PAYABLE DEFERRED PORTION

Annual performance	<85 threshold 100 target		150 max
Deferred incentive (in % of Faxed Rem.)	33%	68%.	191%

Variable remuneration: long-term equity-based incentive

The 2023-2025 Equity based LTI Plan, approved by the Board of Directors on March 16, 2023 and by the Shareholders' Meeting of May 10, 2023, provides for three annual awards starting from 2023, each with a three-year performance period, in accordance with the chart below, unchanged with respect to the 2023-2026 policy approved the previous year.

CHART 11 - LTI EQUITY-BASED PLAN TIMELINE

PERFORMANCE AND VESTING PERIOD
YEAR T	YEAR T+1	YEAR T+2	YEAR T+3
-> Award of shares			- Granting of shares

(23) The deferred incentive values as a % of fixed remuneration shown in the table were calculated as follows:

• Theeshold: 38% = 35% x (150% x 85%) x 85%) x 85
• Target: 68% = 35% x (150% x 100%) x 130

· Max: 181% = 35% x (150% x 150%) x 230

INTRODUCTION EXECUTIVE SUMMARY

PERFORMANCE CONDITIONS

The Plan's performance targets have been further adjusted to developments in Eni's strategies and to the target of alignment with stakeholder interests. In particular, these objectives are structured as follows

• 1) 25% Market Target: linked to Total Shareholder Return (relative);
• 2) 40% Economic and financial target: Organic Free Cash Flow (absolute);
• 3) 35% Environmental Sustainability and Energy Transition objective (absolute), structured as follows:
  • 3.1) 10% Decarbonisation objective;
  • 3,2) 15% Energy Transition target, structured according to two indicators both

with a weight of 7.5%;

3.3) 10% Circular economy Target.

The detailed descriptions of each indicator are given below:

1) Market Target: the difference between the TSR of the Eni share and the TSR of the FTSE MIB index of Boraa Italiana, adjusted by the Eni correlation index, compared with the equivalent adjusted TSR measures for each company of the Peer Group, as shown in the following formula:

Where:

TSR .: TSR of Eni or of one of the companies of the Peer Group,

TSR of the reference stock market index of the company to which the TSRco applies;

Correlation coefficient between the performance of the shares and the performance of the reference market (FTSE MIB, S&P 500, FTSE 100, CAC 40, AEX, OBX, ATX and IBEX 35).

This indicator makes it possible to neutralise the effects of developments in the respective stock markets on the TSRs of each Company, taking into account the correlation index between the stock and the market over the three-year penod.

The benchmark Peer Group is made up of 6 European companies in the Energy sector characterised by an integrated portfolio and similar energy transition and decarbonisation paths as Enc Shell, BP TotalEnergies, Equinor, Repsol, OMV.

• 2) Economic and financial target: value of the organic Free Cash Flow cumulated in the threeyear reference period compared to the equivalent cumulated value provided for in the first 3 years of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged during the performance period.
• 3) Decarbonisation objective value verified at the end of the three-year period of Upstream net GHG emissions Scope 1 and Scope 2 equity (tCO2eq.), compared with the same value expected in the 30 year of the Strategic Plan approved by the Board of Directors in the year of attribution and kept unchanged over the performance period.
• 4) Energy Transition objective: Installed capacity of electricity generation from renewable sources (MW) and biojet fuel production capacity (kton) measured at the three year performance period, compared with the same value expected in the 3m year of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged over the performance period.
• 5) Circular Economy objective: proportion of vertical integration of the agribusiness for biofuel processing compared to the value expected in the 30 year of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged over the performance period

Verification of absolute parameters is done net of the effects of external variables (e.g. oil and gas prices, the Euro/dollar exchange rate), as well as events which by their nature cannot be attributed to management performance, based on the gap analysis method approved by the Remuneration Committee.

Objectives of the ILT Plan equity 2023-2025

ANNEX

Verification of results

2023-2025 Long-Term Equity-Based Incentive Plan 2024 Award

According to the provisions of the Information Document of the 2023-2025 Long-Term share Plan, available on the Company's website, table 14 shows the three-year performance levels of the absolute objectives of the first award of the Plan (award 2024, with performance period 2024-2026). The mentioned performance targets were approved by the Board of Directors, on the proposal of the Remuneration Committee, at the meeting of March 13, 2024.

TABLE 14- ARSOLUTE 2024-2026 TARGETS FOR THE 2024 AWARD OF THE 2023-2025 LTL SHARE-BASED PLAN

Absolute targets	Indicator	Measurement unit	Threshold 80%.	Target 180%	Maximum 180%
FCOnsistic-financial target	Furo hillions curnulated in the Organic Free Cash How three-year period 2024-2026		10.47	11.22	12.72
Dicarbonisation target	Net emissions upstream Scope 1 and 2 - equity	MtorDOleq in 2026	46	44	4.2
Energy transition:	Blectncity generation clapscity from renewables - Pienitude 100%	MW of installed capacity at 1231 2026	e a73	7415	7,857
	Biojet production capacity	kton/year Biojes production capacity at 12.31.2026	261	275	289
Citcural economy	Agnbusiness vertical integration (Italy perimeter)	Proportion of Agribusiness Volumes out of Total Processing (%) in 2026	30.5%	43%	46.5%

INCENTIVE MECHANISMS AND LEVELS

The annual award of shares is calculated using the following formula:

No. of shares awarded = FR X %1 TAPET P Att

Where FR is total fixed remuneration, is the incentive percentage at target performance level (150% of the fixed remuneration for the Chief Executive Officer) and P _ is the price of the award calculated as the average of the daily official prices (source: Bloomberg) recorded in the 4 months before the month in which the Board of Directors approves the award to the Chief Executive. Officer and the Plan rules.

The grant of shares at the end of the three-year vesting penod is determined using the following formula:

No. granted shares = no. awarded shares x M2

In which the final multiplier Mf is equal to the weighted average of the multipliers of each indicator. For the relative indicator linked to the TSR, the multiplier may be between zero and 180%, with a threshold set at a median level, in accordance with the scale shown below.

Ranking
1º	2	m	5	in	6°	1
Multiplier
180%	140%	100%	80%	0%	0%	as

TABLE 15 - PERFORMANCE SCALE - RELATIVE PERFORMANCE SCALE MULTIPLIER (TSR)

ANNEX

For absolute targets (Economic and Financial, Decarbonisation, Energy Transition and Circular Economy objectives), the result will be measured based on a partial multiplier between zero and 180% determined as a function of performance, as in the following chart:

The table below shows the thresholds, targets and maximum monetary value of shares (as a percentage of fixed remuneration) grantable to the Chief Executive Officer at the end of the vesting period, net of any effects due to changes in the share price24.

TABLE 16 - VALUE LEVELS OF GRANTED SHARES

Average 3-year weighted performance		<40 threshold 122.5 target 180 max
Value of shares (in % of Fixed Rem.)	0%		60% 60% 1 183.75%	2/0%

The 2023-2025 Plan Rules envisage for the Chief Executives in service, that 50% Shareholding Policy of the shares awarded at the end of the vesting period are to remain restricted for 2 years from the granting date. For the CEO/GM, this would be equivalent, in the event of shares granted annually equal to the value of the LTI awarded, to a shareholding objective (achievable within 2 years) equal to 1.5 times the fixed remuneration.

In the event of early termination for the Chief Executive Officer, due to resignation and not justified by a substantial reduction in powers or of termination for just cause, all rights to the award and payment of incentives shall lapse.

In the event of termination related to expiry of the Board of Directors without renewal, the grant of Eni shares of each award will be prorated with respect to the period of permanence in office, according to the results verified over the same period.

(24) The incentive values as a % of fixed remuneration shown in the table were calculated as follows

· Target: 183.75% = 150% x 122.5%

· Mux 270% = 150% x 180%

Pro-rata mechanism in case of consensual termination of the CEO

Malus/Clawback

All variable incentives in favour of the Chief Executive Officer are subject to the malus/clawback clauses envisaged in En's Remuneration Policy, described in the General Principles chapter.

Non-monetary benefits

The following benefits are envisaged for the Chief Executive Officer in line with the Eni policies established for all Executives: (i) insurance coverage for death and permanent disability, for occupational injury and disease and elsewhere; (ii) supplementary pension and healthcare plan; (iii) company car.

Pay mix

Pay mix with a dominant weighting attributed to the variable long-term component

The remuneration package for the Chief Executive Officer includes a fixed component, a short-term variable component, and a long-term variable component (deferred portion of the short-term incentive and equity-based long-term incentive) determined using internationally recognised methodologies for remuneration benchmarks.

The pay mix is weighted significantly towards the variable components, with a dominant weighting attributed to the long-term component, as shown in the figure below.

CHART 13-PAY MIX CEO

Employee Stock Ownership Plan 2024-2026

Based on that established in the Information Document for the Employee Stock Ownership Plan 2024-2026, available on the Company's website, the Chief Executive Officer and General Manager participate in the Plan, albeit with a purely symbolic annual grant of 1 Eni share.

Payments due in the event of termination of office or employment25

SEVERANCE PACKAGE

For the position of Chief Executive Officer: an indemnity in the event of early termination or nonrenewal of the office, as well as resignation justified by a reduction of delegated powers, set at two years of fixed remuneration for the position, as already provided for in the 2020-2023 term, in line with Recommendation 2009/385/EC.

For the position of General Manager: indemnity in the event of the consensual termination of the management relationship, set at two years of fixed remuneration plus short-term incentive, below the maximum protections of the appropriate national collective bargaining agreement providing for up to

(25) Information also provided in accordance with Article 123-bis, paragraph 1, letter i), of the Consolidated Law on Finance:

LETTER INTRODUCTION EXECUTIVE SUMMARY

39

three years of total actual remuneration, including fixed remuneration, short- and long-term variable incentives, and benefits20.

Also with reference to Recommendation no. 27, letter f) of the Governance Code, these indemnities cannot be paid in the event of termination and/or dismissal with just cause or resignation of the interested party not justified by a substantial reduction in powers, as well as in the circumstances set out in Art. 2122 of the Italian Civil Code.

NON-COMPETE AGREEMENT

In relation to the continued employment relationship, the non-compete agreement already activated after the Board of Directors exercised its option right on March 14, 2019, will be maintained. The obligations under the Agreement establish a period of efficacy of 18 months with non-competition constraints for the Oil & Gas sector applying to 19 countries, supplemented with respect to companies operating in the circular economy sector. The remuneration for the Agreement, defined in relation to the obligations, envisages a fixed component of €1,800,000, plus a variable component, to be determined as a function of the average results for the STI Plan in the previous three years, between €500,000 (target performance) and €1,000,000 (maximum performance).

Managers with Strategic Responsibilities

For General Managers and other Managers with Strategic Responsibilities, the 2024 Remuneration Policy is unchanged on that for the previous term, maintaining remuneration plans that are strictly in line with those of the Chief Executive Officer, to better guide and align managerial action with the objectives set out in the Company's Strategic Plan, and with the provisions and protections laid down by national collective bargaining agreement for executives.

In particular, the Short-Term Variable Incentive Plan with deferral and Equity-based Long-Term Incentive Plan - intended for the Chief Executive Officer apply.

Fixed remuneration

Fixed remuneration is deternined based on the role and responsibilities assigned considering a prudent positioning with respect to the median benchmarks of national and international executive markets for roles of a similar level of responsibility and managerial complexity.

Remuneration may be updated, during the annual salary review involving for all managers, according to selective criteria that envisage increases to the fixed/one-off remuneration for those in positions that have seen a significant increase responsibility or scope, and to address retention risk and reward excellent performance. In addition, in their capacity as Eni officers, Managers with Strategic Responsibilities are entitled to receive allowances due for travel in italy and abroad, in line with applicable provisions of the Italian national collective bargaining agreement for executives and supplementary Company agreements.

Variable Incentive Plans

SHORT-TERM VARIABLE INCENTIVE PLAN WITH DEFERRAL

Managers with Strategic Responsibilities participate in the Short-Term Incentive Plan with deferral, already described for the Chief Executive Officer. The related individual targets are consistent with those assigned to the Chief Executive Officer in the context of the same policy clusters, consistent with the responsibilities of the role and the provisions of the Company's Strategic Plan.

(26) in cases of fermination not due to just cause, CCNL protections call for up to a maximum of 36 morths of total remuneration (fored remaneration, variable short and long-term incentives, benefits), including that observilly, consistent with national regulations (article 2121, Chil Code)

Incentive Plans closely consistent with those provided for the CEO/GM

Fixed remuneration based on roles and responsibilities

For Managers with Strategic Responsibilities, the target incentive levels for the Short-Term Variable Incentive Plan differ depending on the role's level of responsibilities and complexity up to 100% of fixed remuneration, with a maximum incentive level payable for the annual and deferred portions of 98% and 121% of fixed remuneration, respectively.

LONG-TERM VARIABLE INCENTIVE PLAN

Managers with Strategic Responsibilities participate in the 2023-2025 Long-Term Incentive Plan. The Plan is directed at managers who are critical for the business and envisages three annual awards, starting in 2023, with the same performance conditions and characteristics as those described above for the Chief Executive Officer.

For Managers with Strategic Responsibilities, the value of the shares to be awarded each year differs depending on the level of their role and is limited to a maximum of 75% of fixed remuneration, with the maximum grant corresponding to 135% of fixed remuneration, calculated with reference to the price at which the shares were awarded.

DISK MITIGATION CI AUSES

For General Managers and other Managers with Strategic Responsibilities, the same malus/ clawback and share lock-up clauses envisaged for the Chief Executive Officer and the General Manager apply.

Non-monetary benefits

CHART 14 - PAY MIX MSRs

The following benefits are envisaged for Managers with Strategic Responsibilities, as defined in national collective bargaining agreements and supplemental company agreements for all Eni executives: (i) life insurance and insurance against permanent disability due to workplace or other injury or illness; (ii) supplementary pension plan (FOPDIRE fund) and supplementary health plan (FISDE fund); (ii) company car for business and personal use and possible housing for operational and mobility requirements.

Pay mix

The remuneration package for Managers with Strategic Responsibilities, as for the Chief Executive Officer, includes a fixed component, a short-term variable component, and a longterm variable component (deferred portion of the short-term incentive and equity-based longterm incentive) determined using internationally recognised methodologies for remuneration benchmarks

As shown by the chart, the pay mix maintains a significant focus on the variable components, with prevalence of the long-term component, in line with the practice of the benchmark markets.

Long-term incentive Short-term incentive Fixed remuneration Target Maximum 200

Balance between fixed and variable remuneration in relation to level of responsibility and impact on business

<-- PDF CHUNK SEPARATOR -->

INTRODUCTION EXECUTIVE SUMMARY SECTION I

ANNEX

Employee Stock Ownership Plan 2024-2026

Based on that established in the Information Document for the Employee Stock Ownership Plan 2024-2026, available on the Company's website, Managers with Strategic Responsibilities participate in the Plan, albeit with a purely symbolic annual grant of 1 Eni share.

Payments due in the event of consensual termination of employment

Managers with Strategic Responsibilities, like all Eni executives, are entitled to severance benefits for employment termination established by law and in the CCNL for industrial Managers together with any termination indemnities agreed on an individual basis, in accordance with the criteria established by Eni for cases of retirement incentives, taking into account the position held and performance, within the limits of protections envisaged by the same collective bargaining agreement and consistent with application criteria of the Italian Corporate Governance Code (Recommendation no. 27, letter f). These protections envisage, in cases of termination without just cause, up to a maximum of three years of total actual remuneration, calculated in line with the provisions of Art. 2121 of the Civil Code®7 and of the CCNL for industrial executives (Art. 19).

For cases of termination that present high competitive and litigation risks relating to the nature of the position, agreements may contain additional non-compete clauses, with duration up to one year and payments defined in relation to remuneration level, scope, duration and effectiveness of the agreement. The consensual termination of the employment relationship entails, for the beneficiaries of Long-Term Incentive Plans, the pro-rata payment of the incentives in proportion to the vesting period that has elapsed, taking into account.

Consistent with national requlations and the CCNL for industrial executives

Section II Compensation and other information

This Section will be subject to a non-binding vote during the Shareholders' Meeting of May 15, 2024, according to the provisions of the applicable legislation.

INTRODUCTION

In accordance with the Consob Issuers Regulation, Section II reports the remuneration for 2023 on an accrual basis, showing fixed remuneration accrued in 2023 and short and long-term variable incentives accrued with respect to the final performance in 2023 and payable/grantable in 2024.

As regards the 2024 Short-Term Incentive accrued in 2023 for Chief Operating Officers and other Managers with Strategic Responsibilities, since individual performance results are unavailable at the date of approval of this Report shows the value of incentives envisaged by the Policy at the level of individual target performance.

As regards the Long Term Equity Incentive awarded in 2021 with accrual period 2021-2023, since the final results of the parameter NPV of Proven Reserves of hydrocarbons are available only after the publication of the financial statements of the companies making up the Peer Group, the Report shows the value of incentives based on an estimate of the final multiplier calculated on the results already recorded and an estimate of the 2023 result of the stated parameter NPV of Proven Reserves at target level. The incentives that will actually be paid/granted in 2024, both relating to the Short-Term Plan and the Equity-Based Long-Term Incentive Plan, will be disclosed in the Remuneration Report to be published in 2025.

Finally, Section II of this Report provides additional information on the implementation of the remuneration policies for 2022, concerning the values of incentives actually parted in 2023 and for which, at the date of approval of the 2023 Report, the data necessary for verifying the performance results were not available.

Disclosure on remuneration changes

For the Chairman and the Non-Executive Directors and Statutory Auditors, there were no changes in remuneration in 2023 compared to 2022, their remuneration having remained unchanged.

For the Chief Executive Officer and General Manager, fixed remuneration for 2023 remained unchanged, while overall 2023 remuneration, incentives paid on verified performance, showed a change of 32% over 2022, mainly reflecting the change in the Equity-Based Long-Term Incentive Plan granted in 2023 compared to the previous year, in relation to the increase in the Eni share price at the grant with respect to the time of awarding (€15.27 vs. €8.21).

ANNEX

TABLE 17 - REMUNERATION PAID TO THE CEO/GM IN 2019-2023 (THOUSANDS OF EUROS)

Your	Fixed Remuneration	Annual Bonus	Long-Term Incentives	日の11の はず	Total	% change
2023	1,600	2,059	6.4224	32	10,112	32%
2022	1,600	2,106	3.934N	31	7,671	5%
2021	1,600	2.1539	3,48811	44	7,285	43%
2020	1,600	1,981	1.469H	40 -	5,090	-115
2019	1,600	1.981	106682	23	5.694	್ತಿ

(a) looked the delered portion of the Short-Fern incentree warded in 2020 and account in the period 2020-2022 (42,134 thousand) and the talaste wale of the shares or a 2020 million to the 2002 Ul Par (4,288 mosed in 2017 and the print 2017 (2,107 thoused and the tackle also di be
the relative in 2021 in the Sterlifer increased i

(i) The Bround Carlor (e 1.3) Stocker (en 2020) Black (en 200 LET/P to 200 (e) (e) Privated and he talad elace (e.
(d) Include the Edente and the 2018-2019 (e.) Pin incente i deferral in 2022 of 50% of the incentive.

differed Moreley Incentive awarded in 2017 and actived in the pend 2017-2019. The amount part came to 4.75 thousens, refecting the further defensi in
2021 of 50% of fire norm

[1] Includes payment of defened Marelary licestive awarded in 2016 (E1,449 thiusand) and Long-level incessive awarded in 2016 (867) Pousanti).

For the Chief Operating Officers the change in the remuneration from 2020 reflects mainly the change in the holders of the positions.

TABLE 18 - REMUNERATION PAID TO THE CHIEF OPERATING OFFICER NATURAL RESOURCES IN 2020-2023 (THOUSANDS OF EUROS)

Year	Fixed Remuneration	Annual Bonus	Long-Torrn SSATIOSPORIT	Benefits	Total	% change
2023	165	613	41000	15 0 - 1	1,803	વું મુ
20224	682	759	194H	12	1,647	-16%
1000 2021	098	7579	289"	12	1,956	38%
20200	714	528	-1684	11	1,421

[a] includes the seferred partion of the Short Tem interest in 2020 and account of the pend 2020 2022 (152 than seems and the the shares granted in 2021 in reason to the 2020 2022 LT Plan (CSB Blouser).
[b] The antacts include renuneration and in Edoury 6, 2022 by Mr Pall and subseppedly to Mr Brusso

if insusted one the east in 2014 and and one of the production the pared 2019 and the shares gramel in 2022
in electronic 2019 and of the 2019 in Par (Cith bosand
ift) The

in thouses defened partion of the Stort-Term received in 2018 and accued in the period 2010-2020 19764 moxions and the charge le) hthudes allerial pontine and the 2017 and and of 2018 and activel of the Incorn (and 10 le linceard) and the same and the cateller and of the catelling the final collecti

[] The position and established an July 1, 2020, illerition in the volulation and the volvers cast on partialy at instilly at totaly and buttle) to be prosisus. role held.

(in Defensi Monetary maentye ewarded in 2017 and scoued in the pencol 2017 2019. The amount paid came to 634 thousand, refecting the further before in 2021 of 50% of the incentive.

Year	FIXed Remuneration	Annual Bonus	Long-Term Incontives	Benefits	Total	% change
2023	766	629	00891	16	2,319	22%
2022	715	565	60701	13	1,900	3%
2021	689	55610	581m	13	1,839	-22%
A 17 100 1 2020140	Basi	1 - 1 - 1 725	72941	13	2,360

[i] helsides defered prive of the Short-Term iscentive awarded in 2020 and accuration in the period 2000-2022 (419.8 housand) and the states in 2023 in relation to the 21 ard of the 2020-2022 LTI Plan (4.490 thouse [b] hotiales defened portion of the Short Tem incentive ewarded in 2019 and accried in the penind 2019 2121 (1396 thousing) and the stares

granted in 2022 in relation to the 2019 award of the 2017-2019 LTI Plan (C209 thousand) ic) The anousl partion of the Short Trensities in 2072 of the arrast 250 bortes in 2021.
(d. Includes delimed portion of the Short Time incread in 2073 and scened in the pend

granted of 2021 in reston to the 2017 2019 UT Pan (LD3 thrusan). The anount paid care to C392 thousand refecting the future of further of further of further of further of fur (e) The position was essokered in July 1, 2020, therefore the fiscusse incentives paid are partially of artify a firflussion one previous

pight heid.

I (I The psociences by Mr. Massero Monska Port July 1, 2020 to Becember 3, 2020.
(g) Drivers Messay Incorded in 2017 and accuration to the price 2017-02010. The annoxt pad c

For Eni employees in Italy, the change in total remuneration in 2023-2022 came to an average +4.5%. This figure is 5.2% it newly acquired companies are not considered. The change is in part due to initiatives implemented by the company to protect the purchasing power of employees against the high inflation seen during the period. The change in 2022-2021 was +4.1%, and in 2021-2020 was +0.9%.

In 2023 Eni achieved excellent economic and financial results, supported by industrial management. in which asset integrity played a key role, guaranteeing the sustainability of production targets, as did financial discipline. Pro forma adjusted operating profit (including the Eni portion of the contribution from our affiliates) was around €18 billion; adjusted net profit was €8.3 billion. Cash flow generation was robust with €16.5 billion in operating cash flow before the change in working capital, which net of organic capex of €9.2 billion shows an organic FCF of €7.3 billion, much higher than the still excellent cash return seen by the shareholders during the year of €4.8 billion, in the form of €3 billion in dividends and the execution of a buy-back plan with an outlay of £1.8 billion. These results allowed the Group to achieve a solid asset structure, with 20% leverage.

IMPLEMENTATION OF THE 2023 REMUNERATION POLICIES

The implementation of the Remuneration Policy covering 2023 for Directors, Chief Operating Officers and other Managers with Strategic Responsibilities was verified by the Remuneration Committee during the periodic assessment provided for in the Corporate Governance Code and was found to be compliant with the Remuneration Policy approved by the Shareholders' Meeting on May 10. 2023, kept unchanged with respect to the previous term, based on decisions taken by the Board of Directors on June 1, 2023.

Verification of 2023 performance for the purpose of the accrual of incentives payable and/or grantable in 2024

This section covers the verification of results for 2023, as approved by the Board of Directors on March 13, 2024 for the purpose of incentives payable/grantable and/or awardable in 2024 to the Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with Strategic Responsibilities.

ANNEX

Deferred Short-Term Plan (STI Plan) 2024

VERIFICATION OF OBJECTIVES 2023

Verification of the objectives assigned to the Chief Executive Officer and General Manager for 2023 was approved by the Board, following verification and a proposal from the Remuneration Committee, at its meeting on March 13, 2024, with a performance score of 140 points calculated.

The table below shows the weightings and performance achieved for each objective.

Performance targets	weight	Measurement Target Unit			Result Minimum 70	Budget 100	Maximum 130	Over performance 150	Performance	Score score Weighted
Economic and financial results	25.0									37.6
EBT (Earning Before Tax) adjusted	125	Chilion	10.8	15.1					150	188
Organic Free Cash Flow	12.5	C billion	3	6,1					150	188
il. Operating results	25.0									31.8
Hydrocarbon production	125	Kboed	1,636	1,665					119	149
Incremental installed renewable свресіту	12:5	MAY	973	1,068					135	16.9
III. Environmental sustainability and human capital	25.0									33.0
Seventy Incident Rate (SIR) - employees and contractors weighted	12.5	1	25	13					133	16.7
Upstream net emissions Scope 7 and Scope 2 equity	12.5	MionColeg	03	8.9					130	163
iv. Efficiency and financial strength	25.0									37.6
RONCE (Return On Average Capital Employed) adjusted	125	if?	8 @ 0	12:31					150	188
Net Debt/EBITDA adjusted	12:5	HOICAO	0 00	0.74					150	188
TOTAL										140

TABLE 20 - VERIFICATION OF 2023 OBJECTIVES

(s) (paircedable multiples waiting in swerphous ware managements comments comments comments comments to designed and most to the process verifying the nelative implementation and internationalisation of the behaviours requested.

Verification of objectives was conducted using the gap-analysis methodology approved by the Remuneration Committee, which calls for neutralisation of external factors such as the commodity price situation and exchange rates, as well as events that by their nature are not attributable to management performance, so as to ensure results can be accurately compared with the targets assigned. The following are the main results for each objective:

• · EBT: the result was better than the target, in particular with reference to the record result for GGP due to optimisation of the natural gas and LNG portfolio and renegotiations of contracts, UPS cost efficiency, as well as improved performance for GTR&M and Plenitude;
• · Free Cash Flow: an improvement compared to the target as a consequence of excellent economic results, as well as widespread optimisation;
• · Hydrocarbon Production: higher than the target thanks to higher contributions coming from Libya, Algeria, Indonesia and Venezuela;
• · Incremental Installed Renewable Capacity, an improvement on the target, achieved through developing the project pipeline and selective portfolio operations,
• · Severity Incident Rate (SIR) an improvement with respect to the target, confirming Enis commitment to utilising new tools intended to disseminate a culture of safety at all company levels, affecting worker behaviour and more closely montoring the in the field activities of our partners;
• · Net emissions upstream Scope 1 and 2 equity, the result benefited from actions to optimise operating management and make it more efficient;
• · ROACE: this performance was achieved by improving economic results;
• · Debt/EBITDA: this result is the consequence of better economic and financial results.

Deferred Short-Term Plan (STI Plan) 2021

DEFERRED PORTION 2021 VERIFICATION OF 2021-2023 OBJECTIVES

The 2021 STI Plan provided for a deferred portion of 35%, depending on the annual performance of Eni in the 2021-2023 period. On March 13, 2024, the Board of Directors, acting on the proposal of the Remuneration Committee, approved a 2023 performance score of 140 points resulting in a 2023 multiplier of 210%.

With reference to the multipliers already determined for 2021 and 2022, the final multiplier to be applied to the 2021 deferred portion for payment in 2024 came to 201%, as shown in the table below.

TABLE 21-FINAL MULTIPLIER OF THE STI DEFERRED PORTION ACCRUED IN 2021-2023

	2021 performance	2022 performance	2023 performance	Final multiplier for payment 2023
Ent performance scope.	135	132	140
Multiplier	200%	194%	210%.	201%

Equity-Based Long-Term Incentive Plan (LTI Plan) 2020-2022

2021 AWARD VERIFICATION OF 2021-2023 RESULTS

The 2020-2022 Equity-Based LTI Plan provided for 3 annual awards connected to the performance of the relative parameters for TSR and NPV of Proven Reserves and the absolute Economic/Financial, Decarbonisation, Energy Transition and Circular Economy parameters.

For the 2021 award, the performance results for 2021-2023 will only be available after approval of the Eni Financial Report and publication of the Financial Statements of all the companies in the Peer Group.

Equity-Based Long-Term Incentive Plan (LTI Plan) 2023-2025

2023 AWARD

For the initial award for the new Equity-based LTI Plan 2023-2025, the Board of Directors, at the meeting on October 26, 2023, after verification by and on a proposal of the Remuneration Committee, approved the award price of £13.8641, calculated according to the criteria established in the Plan.

Remuneration accrued and/or awarded in 2023

This chapter describes the remuneration accrued and/or awarded in 2023 to the Chairman of the Board of Directors, Non-Executive Directors, the Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with Strategic Responsibilities in accordance with the 2023-2026 Remuneration Policy and in relation to the performance levels achieved during the period in which they held their respective roles.

Details of this remuneration can be found in the tables in this chapter.

Chairman of the Board of Directors

FIXED REMUNERATION

For the Chairwoman in office until May 10, 2023, (Lucia Calvosa), pro-rated remuneration was paid as established for the position and the delegated powers respectively approved by the Shareholders' Meeting on May 13, 2020 and the Board of Directors on June 4, 2020,

ANNEX

For the Chairman in office as from May 11, 2023 (Giuseppe Zafarana), pro-rated remuneration was paid as established for the position and the delegated powers respectively approved by the Shareholders' Meeting on May 10, 2023 and the Board of Directors on June 1, 2023, and kept unchanged with respect to the previous term.

NON-MONETARY BENEFITS

For the Chairwomen in office until May 10, 2023 (Lucia Calvosa), in line with that approved by the Board of Directors on June 4, 2020, a life insurance policy and an insurance policy against permanent disability due to injury or illness contracted in the workplace or elsewhere were provided. as well as supplemental healthcare coverage.

For the Chairman in office as from May 11, 2023 (Giuseppe Zafarana), on June 1, 2023, in line with the Remuneration Policy approved by the shareholders on May 10, 2023, the Board of Directors granted a life insurance policy and an insurance policy against permanent disability due to injury of illness contracted in the workplace or elsewhere.

Non-executive Directors

For non-executive Directors in office until May 10, 2023, pro-rated remuneration was paid with respect to the fixed remuneration approved by the Shareholders' Meeting on May 13, 2020, as well as pro-rated amounts for the additional remuneration due for participation on Board Committees, based on that approved by the Board of Directors on June 4, 2020,

For non-executive Directors in office as from May 11, 2023, pro-rated remuneration was paid as established for the position and the delegated powers respectively approved by the Shareholders' Meeting on May 10, 2023 and the Board of Directors on June 1, 2023, and kept unchanged with respect to the previous term.

Board of Statutory Auditors

The Chairwoman and members of the Board of Statutory Auditors in office until May 10, 2023 were paid pro-rated amounts of the lixed remuneration approved by the Shareholders' Meeting on May 13, 2020, as well as any additional remuneration established for offices held in subsidiaries.

The Chairman and members of the Board of Statutory Auditors in office as from May 11, 2023 were paid pro-rated amounts of the fixed remuneration approved by the Shareholders' Meeting on May 10, 2023, kept unchanged with respect to the previous term, as well as any additional remuneration established for offices held in subsidiaries

Chief Executive Officer and General Manager Claudio Descalzi

FIXED REMUNERATION

The Board of Directors, at its meeting on June 1, 2023, kept unchanged, with respect the previous term, the total fixed remuneration of the Chief Executive Officer and General Manager, for whom the position was renewed, continuing the executive employment relationship, at €1,600,000 (€600,000 for the role of Chief Executive Director and £1,000,000 for the role of General Manager), in accordance with the Remuneration Policy for the 2020-2023 term approved by the Shareholders' Meeting of May 10, 2023. This remuneration includes the remuneration determined by the Shareholders' Meeting for Board of Directors members as well as any remuneration due for participation in the Boards of Directors of Eni subsidiaries and/or shareholdings.

NON-MONETARY BENEFITS

In accordance with the Remuneration Policy approved by the shareholders on May 10, 2023, the Board of Directors, meeting on June 1, 2023 decided to confirm the same benefits already provided for in the previous term (life insurance policy and an insurance policy against permanent disability due to injury or illness contracted in the workplace or elsewhere. Also provided, provisions contained in the national collective bargaining agreement and the supplementary company agreements for Eni senior managers, a company car for business and personal use).

2024 DEFERRED SHORT-TERM INCENTIVE (STI) - ACCRUAL OF ANNUAL PORTION AND AWARD OF DEFERRED PORTION

The 2024 STI Plan was implemented in in accordance with the criteria and methods provided for in the 2023-2026 Remuneration Policy. Accordingly, in relation to the results obtained in 2023 and approved by the Board of Directors on May 13, 2024 (140 points), an annual incentive of €2,184 thousand was accrued, with the awarding of a deferred incentive of £1,176 thousand (respectively 65% and 35% of the total incentive of €3,360 thousand).

2021 DEFERRED SHORT-TERM INCENTIVE - ACCRUAL OF DEFERRED ANNUAL PORTION

The deferred portion of the STI awarded in 2021 accrued for €2,330 thousand in 2023, based on the final multiplier verified in the 2021-2023 performance period (201%) approved by the Board of Directors on March 13, 2024.

2020-2022 EQUITY-BASED LONG-TERM INCENTIVE PLAN - ACCRUAL OF THE 2021 AWARD

In 2023 the incentive awarded in 2021 accrued, relative to the 2020-2022 Equity-Based Long-Term Incentive Plan. The actual number of shares to be granted will be determined after verification of the performance results which were not yet available as of the date of approval of this Report.

An estimate of the number of shares which may be granted is found in table 3 in this section, under the item "Financial instruments vested during i the year and grantable", based on current progress in the results for the performance period in question.

2023-2025 EQUITY-BASED LONG-TERM INCENTIVE PLAN - 2023 AWARD

In implementation of the 2023 2025 Equity Based Long Term Incentive Plan, approved by the Shareholders' Meeting of May 10, 2023, the Board of Directors resolved on October 26, 2023 to award to the Chief Executive Officer and General Manager 173,109 Eni shares, determined on the basis of the incentive percentage to be applied to total fixed remuneration (150%) and the award price resolved by the Board (€13.8641).

SEVERANCE INDEMNITY FOR END-OF-OFFICE OR TERMINATION OF EMPLOYMENT

In 2023, the conditions for application of the severance indemnity for end of office or termination of employment resolved by the Board of Directors on June 1, 2023 were not fulfilled, in line with the Remuneration Policy approved by the Shareholders' Meeting on May 10, 2023.

SUMMARY OF REMUNERATION ACCRUED BY THE CEO/GM

Below is a summary of the remuneration accrued in 2023 for the Chief Executive Officer and General Manager, (consistent with Table 1 of the chapter "Remuneration accrued in 2023"), and the related pay mix.

TABLE 22 - SUMMARY OF REMUNERATION ACCRUED FOR THE CEO/GM IN 2023

			Fixed Remuneration Annual Bonus Long-Term Incentives Benefits Total
Amount (thousands of euro)	1.600	2,184	23309	32 6,146
Pay mix (%).	26%	36%	38%	1%. 100%

(i) broutes the defension of the Short-Term incertive 2021 accrued in 2020 2122, dees not include the Egaily Boxed Long-Term leastive 2021 which will be calculated after completion of the final verification proness scheekiled for Juste 2024.

ANNEX

Chief Operating Officers and Other Managers with Strategic Responsibilities

FIXED REMUNERATION

In 2023, within the context of the annual salary review process envisaged for all managers in cases of promotion to more senior levels or in line with necessary market-driven adjustments, selective adjustments were made to fixed remuneration for the Chief Operating Officers of the businesses Energy Evolution and Natural Resources and Other Managers with Strategic Responsibilities.

2024 DEFERRED SHORT-TERM INCENTIVE (STI) - ACCRUAL OF ANNUAL PORTION AND AWARD OF DEFERRED PORTION

The annual and defered portion of the 2024 STI Plan will be paid/awarded in 2024 based on 2023 individual performance, the final verification of which is not available at the date of approval of this Report.

2021 DEFERRED SHORT-TERM INCENTIVE - ACCRUAL OF DEFERRED ANNUAL PORTION

In 2023, the deferred portion of the STI awarded in 2021 accrued based on the final multiplier verified in the 2021-2023 performance period (201%), approved by the Board of Directors on March 13, 2024.

2020-2022 EQUITY-BASED LONG-TERM INCENTIVE PLAN - ACCRUAL OF THE 2021 AWARD

The incentives awarded in 2021, related to the 2020-2022 Equity Based Long Term Incentive Plan, accrued in 2023. The actual number of shares to be granted will be determined after verification of the performance results which were not yet available as of the date of approval of this Report.

An estimate of the number of shares which may be granted is found in table 3 in this section, under the item "Financial instruments vested during i the year and grantable", based on current progress in the results for the performance period in question.

2023-2025 EQUITY-BASED LONG-TERM INCENTIVE PLAN - 2023 AWARD

On October 26, 2023, the Board of Directors approved the 2023 award of the 2023-2025 Equity-Based Long-Term Incentive Plan, approved by the Shareholders' Meeting of May 10, 2023 and granted delegated powers to the Chief Executive Officer and General Manager for the related implementation in favour of the Chief Operating Officers, the Other Managers with Strategic Responsibilities and the managerial resources critical for the business, according to the criteria established by the Plan.

NON-MONETARY BENEFITS

In 2023, the non-monetary benefits provided for in the Remuneration Policy approved by the Shareholders' Meeting of May 10, 2023 were assigned.

SEVERANCE INDEMNITY FOR END-OF-OFFICE OR TERMINATION OF EMPLOYMENT

During 2023, no cases of consensual termination occurred for Chief Operating Officers or Managers. with Strategic Responsibilities.

SUMMARY OF REMUNERATION ACCRUED BY THE CHIEF OPERATING OFFICERS

Below is a summary of the remuneration accrued in 2023 for the Chief Operating Officers (with reference to Table 1 of the chapter "Remuneration accrued in 2023") and the related pay mix,

TABLE 23 - SUMMARY OF REMUNERATION ACCRUED FOR CHIEF OPERATING OFFICER NATURAL RESOURCES IN 2023

			Fixed Remuneration Annual Bonus Long-Term Incentives Benefits Total
Amount (thousands of euro)	765	-5750	24330	15 1,598
Pay mor (%)	48%	36%	1536	7% 100%

(a) Estimate for volvidual performance in rained level 3025 (final verificanon data not being available at the Gare of approval of the Report). ip) Includes the lefter don't of the Short Forn homber 2021 ator not rollable the Equity Basel Long Term Inorthe 2021 which will be

TABLE 24 - SUMMARY OF REMUNERATION ACCRUED FOR CHIEF OPERATING OFFICER ENERGY EVOLUTION IN 2023

			Fixed Remuneration Annual Bonus Long-Term Incentives Benefits Total
Amount (thousands of euro)	766	5598	6010	16 1.942
Paymix (3)	39%	29%	31%	1% 100%

(a) Estrate to halved perience in elatin a large in a stock and the last can be la spoved in the least of the least of the legord and the legord of the legaty-leased included

The tables of the chapter "Remuneration accrued in 2023" show the details of fixed remuneration of the Short and Long Term Incentives accrued in 2023 to the Chief Operating Officers and, in aggregate form, to other Managers with Strategic Responsibilities.

CLAWBACK/MALUS

In 2023 there were no cases of application of the clawback/malus clauses provided for by the Eni Remuneration Policy.

Additional disclosure on the implementation of Remuneration Policy for 2022

To complete information published in Section II of the 2023 Remuneration Report, this section reports the actual values of 2022 remuneration paid/assigned in relation to the final verification of performances completed after the date of approval of the Report, where remuneration had been shown using estimates based on target-level performance.

Equity-Based Long-Term Incentive Plan (LTI Plan) 2020-2022

VERIFICATION OF RESULTS 2020-2022 - 2020 AWARD

In relation to the final TSR result, approved by the Board of Directors on March 16, 2023, as well as venification of the results of the NPV parameter for proven reserves 2022 and the absolute parameters (Economic/Financial, Decarbonisation, Energy Transition and Circular Economy) approved by the Board of Directors on June 1, 2023, the final multiplier for the 2020 award was 96%, as illustrated in the table below.

ANNEX

TABLE 25 - FINAL EQUITY-BASED LTI PLAN 2020 MULTIPLIER ACCRUED IN 2020-2022

Relative targets	96 weight	2020	Result 2021	2022	Multiplier	Welghted multiplier
AT SR 3 year	254	10°			0%	0%.
NPV Proven Reserves	20%	20	50	80
		160%	100%	0%	87%	17%

	96	Targette
Absolute targets	weight	Mirl.	Max	Rosult	Multiplier	Weighted multiplier
Free Cash Flow (billions of euros)	20%	17.08	19:33	19.87	180%	36%
Decarbonisation (tCO_/khom)	15%	206	10.7	20.6	80%	12%
Energy Transition (MW)	10%	1.518	2170	2,156	178%	18%
Circular Economy (projects)	10%	project	3 project	2 project	130%	13%
			Final multiplier			96%

(a might aluster to he are a lease as leasters, for excepted the excepted to the excepted to the one with in the parties on the interest with allifoulde to manigerient jerformance, applying the predetennited method of gap malysis approved by the Renaneration Committee

Verification of absolute targets was done using the gap analysis methodology approved by the Remuneration Committee, which calls for neutralisation of external factors such as the commodity price situation and exchange rate, as well as events that by their nature are not attributable to management performance, so as to ensure results can be accurately compared with the targets assigned. The following are the main results for each objective:

• · Free Cash Flow (organic): exceeded the larget thanks to particularly significant results seen in the GGP sector:
• · Decarbonisation (GHG emissions): in line with the threshold amount;
• · Energy Transition (incremental installed renewable capacity): exceeded the target thanks to accelerated growth, also due to selective acquisitions that were rapidly integrated in the Eni. portfolio:
• · Circular Economy (projects): in line with the target.

Chief Executive Officer and General Manager Claudio Descalzi

SHARES GRANTED (2020 AWARD)

In relation to the verified final multiplier (96%), in November 2023 the Chief Executive Officer and General Manager were granted 280,753 Eni shares, the taxable value of which was €4,288 thousand at the time of grant, also in relation to the increase in the Eni share at the time of grant with respect to the time of award (€15.27 vs. €8.21).

Chief Operating Officers and Other Managers with Strategic Responsibilities

SHARES GRANTED (2020 AWARD)

In relation to the verified final multiplier (96%), the following assignments occurred in November 2023:

• · Chief Operating Officer Natural Resources Guido Brusco was granted 16,904 Eni shares, for a taxable value of € 258 thousand;
• · Chief Operating Officer Energy Evolution Giuseppe Ricci was granted 32,052 Eni shares, for a taxable value of € 490 thousand;
• · other Managers with Strategic Responsibilities were granted a total of 390,715 Eni shares, for a total taxable value at the time of grant of €5,967 thousand.

2023 Deferred Short-Term Incentive (STI) - accrual of annual portion and award of deferred portion

CHIEF OPERATING OFFICERS AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES

Following final verfication of individual performance in 2022, as carried out after the date of approval of the 2023 Remuneration Report, the following payments/assignments occurred;

• · Chief Operating Officer Natural Resources Guido Brusco was paid the annual portion of £613 thousand and awarded the deferred portion of €330 thousand;
• · Chief Operating Officer Energy Evolution Giuseppe Ricci was paid the annual portion of £629 thousand and was awarded the deferred portion of €338 thousand;
• · Other Managers with Strategic Responsibilities, were paid annual portions for a total anount of €7,075 thousand and were awarded deferred portions totalling €3,812 thousand.

ANNEX

REMUNERATION ACCRUED IN 2023

Table 1 - Remuneration accrued to Directors, Statutory Auditors, the Chief Executive Officer and General Manager, Chief Operating Officers and Other Managers with Strategic Responsibilities

In compliance with the provisions of the Issuers Regulation, the table below reports the remuneration accrued in 2022 by Directors, Statutory Auditors, the Chief Executive Officer and General Manager and other Chief Operating Officers, and, in aggregate form, Managers with Strategic Responsibilities, The remuneration received from subsidiaries and/or associates, except that waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year.

In particular:

• · the column labelled "Fixed Remuneration" reports fixed remuneration and fixed salary from employment due for the year (on an accrual basis), gross of social security contributions and taxes to be paid by the employee, in relation to the period in which the office and/or position was held. Details of the compensation are provided in the notes, and any indemnities or payments with reference to the employment relationship are indicated separately;
• · the column labelled "Remuneration for participation on Committees" reports (on an accrual basis) the compensation due to Directors for participation in Committees established by the Board, in relation to the period in which the office and/or position was held. In the notes, compensation for each Committee is indicated separately;
• the column labelled "Variable non equity remuneration" under the item "Bonuses and other . incentives" shows the incentives payable in the following year due to rights vested in the period, following the assessment and approval of related performance results by relevant corporate bodies, in accordance with that specified, in greater detail, in the table 2 "Monetary incentive plans for the Chief Executive Officer and General Manager, for Chief Operating Officers and for other Managers with strategic responsibilities", in the event of unavailability of the performance result at the date of approval of the Report, the table shows the estimate of the incentives accrued considering performance not yet verified at targel level; item "Profit sharing" does not show any figures since no profit-sharing mechanisms are in place;
• · the column labelled "Benefits in kind" reports (on an accrual and taxability basis) the value of any fringe benefits awarded;
• · the column labelled "Other remuneration" reports (on an accrual basis) any other remuneration deriving from other services provided;
• the column labelled "Total" reports the sum of the amounts of all the previous items;
• · the column labelled "Fair value of equity compensation" reports the relevant fair value for the year related to the existing stock option plans, estimated in accordance with the international accounting standards that allocate the related cost in the vesting period;
• · the column labelled "Severance indemnity for end-office or termination of employment" reports indemnities accrued, even if not yet paid, for terminations that occurred during the financial year, or in relation to the end of term in office and/or employment.

TABLE 1 - REMUNERATION PAID TO DIRECTORS, STATUTORY AUDITORS, THE CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES (AMOUNT IN THOUSANDS OF EUROS)

	Notes						Variable non-equity himumation
Name and surname		Position	Prefiod for which the position	Expiration remuner- was held of office®	Fired ation	Remuner- ution for partici- portions in Commit	Bonuses and other tees incontives	sharing	Non Profit monetary	ਾਸ਼ਵ benefits nemuneration		Fair value of passwg-passed Total remuneration employment	Severance Indemnity for endiati office of termination ਹੈ
Board of Directors
Lucia Calvosa	(1)		Chairwoman D1.01-05.10	2023	180m				201		182
Guseppe Zafarana	(2)		Chairman 05 10-12.31	2026	320m						320
Claudio Descalzi	(2)	Chief Executive General Martager	Officer and 01.01-12.31	2026	1,600m		45149		3261		6,146	2068
Ada Lucia De Casaris	(4)		Director 01.01 05.10	2023	200	324					01
Filippo Glansante	(5)		Declar 01.01-05.10	2023	284	124					40
Pietro Angelo Guiltdani	(6)		Director D1.01-05.10	20073	1200	રાજીન					ക്ക
Karina Litusok	(2)		Director 01.01-05.10	2023	20m	31m					દર્ભો
Erranuele Piazinna	(8)		Director 01.01-05.10	2023	244	234					22
Nathalle Tocci.	(प्रत	Deechn	01 01-05 10	2023	299	1000					28
Raphael Louis L. Vermeir	(1 m)		Director 01.01-12.31	2026	BOH	110%					190
Elisa Barondini	Cl 43		Director 05.10-12.31	2006	ಿಗಳ	પિટીન					ਉਤ
Massimo Tieleredi	(12)		Director DS 10-12-31	2026	511	5104					107
Roberto: Cicliani	(1.30		Deechor 15.10-12.31	2004	Hille	274					73
Carolyn Adole Dittricier	(1 4)		Director 05.10 12.31	2026	Clim	િજ્ઞાન					109
Federica Segania	(15)		Director 05.10-12.31	2025	514	644					115
Cristina Sgubin	(TE)		Director Dis. 10-12.31	2007	PIN	5474					105
Board of Statutory Auctitors
Rusalba Casinaghi	(17)		Chainwanan 01.01-12.31	203R	પ્રદાન					રિવિત્ત	150
Firmo Maria Higrami	(1 80	Statutory Auditor DI 01-12 31		2006	75/4					Elli	1384
Marcella Caradonna	(19)	Statutory Auditor 01.01 12:31		2026	754						72
Governiu Ozibell	(20)	Statutory Auditor 01.01-05.10		2023	274						27
Marco Sessoni	(21)	Statutory Audition 01.01-01-01-09		2003	279					10989	130
GIUROPHIEZZO	(22)	Statutiony Auditor 06.10 12.31		2026	12304						ਨੀਤੇ
Andrea Parolini	(23)	Statutory Auditor 05.10-12.31		2025	434						48
Managers with Strategic Responsibilities"
Gaido Brusco	(24)	Chief Operating Officer Natural 01.01-12.31 Pesources			7654		818H		15-		1.500	225
Giuseppe Ricci	(22)	Chief Operating Offices Energy 01.01-12.31 Evolution			7884		1.160p		1652		1.942	311
			Remuneration in the company that prepares the Financial Statements		11,326		13.283		381		104 25,094	3,732
Altri DIRS	(26)		PARCOUNTS And associated	Remuteration from
				TOUSI	11,3269		13,783%		2019		1049 25,094	3,737
					15,901	584	10,775		446		358 37,064	6,336

(*) For Diesses applied by the Oce all elle it hit its Resire (the Receive) to appen the Friences (an Economic 2005)
(*) Esculters with were primated committee committee t

(1) Lucia Catrosa - Chairwomas of the Board of Directors (i) The arcont record redules (if the pression of ant ly the Sunristics' Medity of May 11, 2009, equal to C23 https:// (1) the pross posion of first emarestion of fied benews approved by the Essand for the 2002 2023 write in the Stars of Directors for the Board of the 2020 2023 iem, as hom January 1, 2021

(2) Giuseppe Zafarana - Chairman of the Board of Directors

(i) The arount redules: (j) be provisa portune of fact ty the Sharinbles' Messing of May 11, 2020, equal to 657 & floused (i) the gro-sea porton of free elegres power approved by the Board for the 2023-2026 term, equal to €261.9 thousand.

(3) Claudio Descalzi - Chief Executive Officer and General Manager

(i) The answritinciple for the position of Chef Erestler Office (in the 202-2023 terrequire (in the 202-2023 terrorential for the 202-100. transwood to £1,000 thrusand.

ANNEX

To the proof it and processions in the will the will the will the persisins of the request research and the corporations and to corporarios and the Corporary ageneral for an amount of €17 1 thousant

(2) The proof letades () the arrual price of the minuted in 2022, in the internation attend's 1022 and (i) healtern provins the ST) please in 201 manos acheved in the 2021 2021 2021 period in the amount of CL300 of

rued in in lation to the per g. The antium includes the tissued frisurarie and wellare coyenge, complementary persons and personal varies and personal van.

(4). Ada lucia De Ciesario - Dimenso

ds to the provide postion of the answall feed remumeration set by the Shawholders' Mesting of May 13, 2020.

[3] The anot timbers the personal parties of the Book of Director of the Basil of Directors on particular C1 Browned to the Connection of Pe Connection of Pe Connection of Pe for the Appointments Committee

Fliggo Cia isante Director

(i) The annual porcupords to the arnual frast remail frast remail frast remaineration on by the Shureholders' Meeting of May 12. 2021. It The answer includes the procedes portuned to will be the Brand Species on Specificants on Journition on Journ Contrasting and Sension Common

Pietro Angelo Guindani - Director

(i). The arount composit to be proximal series the ne Breating to March of Starts of Start Commitment (in PS Thoses for the Creatives (13) Thoses for the Creation of Relectio thousand for the Apportiments Committee

Kalea Lituck - Director

ds to the propo propo of the annual fired the Shareholders' Meeting of May 12, 2020. (a) The amount nomes po

3) The enountinistes the possion of the increasion entraliation by the final of Declar to participation on Street and Connites and Connites and Clernites and Clerintes and Cl for the flustanahility and Scimanias Committee

pele Piccinno - Dires

(y) The unusual in the previous polis of the areas and for areas and by De Shandsdains' Meriting of May 12, 2001.

Ch. The provent resident on any of the minutes respirity of the Band of Connections on Eparticulture on particulty of Sensured on 12,6 Streams Comments of Corners Commiss Com €70 E thousand for the Appointments Com nittee

Nathalia Tooci - Director

(a). The anount corresponds to the pro-relax portion of the annual fires renunes to: set the Shanholders' Neeting of May 12, 2011.

To nearchitection of connection neats not the successfore in the control of the controle of R. Housed for Connection of Connection Comment

(TO) Raphuel Louis L. Vermeil - Director

ight for anyont corresponds to the possible of the possession respectively appreved by the Shartholders' Merchips of Mey 10, 2020.

Of The mustification the minutes resultant ly the Econd di Prescus to Beer Currities, in pericals. 432.0 housed to the Cornstoner, in perically 43, bloastillion in the Cornst miller in the ununene be the summit us stress with the summent by 3 brass schimming

[11) Elisa Baroncelli - Director

() The unsuite coresponds to the areal lient in the arrial ford new new of ford memoriations Meeting of May 36, 2022.

(b) The a not related the purporation of the pressure of the Board & Unctions for pertuped in the Summittee, in an our of to personality on of the Summittee and Committee and 619.2 mousand for the Appanenents Committee

[12) Massimo Birloredi Director

onds to the pro-rata portion of the annual fined removenstion set by the Shareholders' Weeting of May 10, 2025.

C) The resument of the prospective continued participation of the Results (Resulters) in processor (Research (Pressual of Child (Resuard to Partices (11) 1) I Benzant

for the Appaintments Committee. (13) Roberto Ciclani - Director

(a) The smasnt comespo

10, 2023. the anyon't is any to see portion of the intrumeration enatined in the Start of Destract or participion on Board In the Sustandity will Senior Cornized (14) Carolyn Adale Dittreaser - Director

do the pro rate portion of the any al fread remaintion set by the linareholders' Newting of May 70, 2022.

0) The around is the possia prior of the envesure establed in the Resord Comities, a paricial 111 I trassed for the Comities, a paricists (11 1 Insuration to the Comites and thousand for the Appointments Committee.

(15) Federica Segarti - Director

(a) The amount consports to the portion of the innus as the investigation the largestered the artist on the 202.

() The around redules to portial of the emergice edististies by Netton for principalite on the Committeer, or princially, in principlian (17 9 tournal for the Committee and \$ thousand for the Sustainability and Scenation: Committees

(16) Cristina Squbin - Director

(a) The nemach composite to the provision of the areast for until resument corner in the Shandreskers' Merling of May 15, 102

Bil The arounded to person of the remeveres withing to the Sale of the Sand of the Searconnelly in prospective in performation in the Committee and C24 sind for the Remurseration Corrently

Rosalisa Casiraghi - Chairwoman of the Board of Statutory Auditors

(g) The amun contespects to the son of the so risk a munistin respectively approved by the sharentifies the sharely in 2020.

DJ The unusuri (consumeration In the novementation In instrument provises proposes profess Ennoo Mana Bignami - Statutory Auditor

(i) The ansiert compilities to the sun in the provention registed by agroved by Re Bluetisties Vilent in May 13, 2220 and May 10, 2022 (f) The revel cornspect to the encurrent info to the books of interest of subsisted a research and, normals (if the more in the increase incorder (a) (18 the marker (a) (18 t VIS NIPHOCHAN Spa

[19) Marcella Caradonna · Statu tay Auction

(i) The emiret componist to the un of the provention respectively aground by the Shareholders' heathing of May 13, 2020 and May 10, 2025.

(20) Giovanna Ceribelli - Statutury Auditor

the to per on on an and first manufactures in the strumption in the server with stores and to to to to to to to to to to to to

(21) Marco Seracini- Statutory Auditor

id The temsurit corresponds to the annual field remansfor not by the Shareholders' Mecting of May 11. 2120. The arround to the post of pronomi let on the happed of manufact of talestions or researce and a portulate to thoused of Vinals. [pk. F I 10 model to V round of Virgin (pk. 1 01

(22) Chulin Palazzo - Statutory Auditor

to the promotion in the are all fine seat on the sense sets in appropriation in apitod prime and the 1) The achitant comes po

(23) Andrea Paralini - Statistory Auditor

(a) The arrant commission in the pro-rests portion of the annual fire to the size shoulders' hereing of May 78, 2022.

(24) Guide Brusco - Chief Operating Officer Energy Evolution

(a) The anount co to to Cours . ( Star Janual I a adderst to do to reserver to on to transition in the with the with the provisions of the newss to promises to tance russupers and the Company's complements or responsive or responsive program a proposation in the manusural

(3) The enquirindes (i) the anal (corner of the 2015) in the encome of 170 leasing of the essurgion of thirdsida perimage enges in 202 line the program and light of infried performance statu at the (date of aggripus) of the Regarly and (ii) The defened and the STIPlar and ed in 2021, accrued in re unce achi If BIC) In the some intone to the nee contribution in the be () The un s the twade with a market and well well as a proponent and the are for business and the care for the prints of offer

(25) Cluseppe Ricel - Chief Operating Officer Energy Evolution,

(i). The record to the program and and the visites that new the week in the west to groupe of the west success collective blooss collective blooss collective blooss collectiv ne neapes art the compress uperient of the meant of 120, in the studio the studio the stumpted in checarity of chieball pertifical perfinition in consistent managing of the l

prisement data a the direct and a the Right Land STIFF a worse of the STIFF a world in 2011, acroad in militir in project many of the 202 202 percept for also a marra of CSI The amount includes the tussible value of insurance and wellare of verage, complementary persion and the use for business and personal use for the period of affice

(26) 0 her Managers with Straingle Responsi ાંદર

(g). The prount to mail take your the ancor in supportunities paid to prophis, in hay and to product of the never most and in entrease subs in collective lobox is collective md with Corpory's additional agreements, as anflas offer internation in anything the a total of FCO fromand.
The anount includes (0) the avoul priors of the 2004-37. Plan acc

(3) toure of CLD07 thousand, based on the easurighton of individual performance at the program manager the organized to the one writed performance data af the Repril, and [i] the Bellerid polition of the ST/Plan weaters actived in 2021 acreed in risked in the 222 202 version polservanor schieved in th 6,774 thousand

(i). Temuri etales to tassisso led lesses and editor in the Contrasta versions and be carter and the Management to the Monagement to the propositars in the propositars in the

Table 2 - Monetary incentive plans for the Chief Executive Officer and General Manager, Chief Operating Officers and Other Managers with Strategic Responsibilities

The table below reports the variable monetary incentives, both short and long-term, envisaged for the Chief Executive Officer and General Manager, the Chief Operating Officers and, at an aggregate level, Other Managers with Strategic Responsibilities (including all individuals who filled these roles during the period, even if for only a fraction of the year).

The column labelled "Bonus for the year" details:

• · under the item "payable" the short-term variable incentive accrued during the year based on the final. venfication of the performance carried out by the competent corporate bodies with reference to the objectives defined for the financial year, in the event of unavailability of the performance result at the date of approval of the Report, the table shows an estimate of the incentive accrued considering performance not yet verified at target level;
• · under the item "deferred", the amount of the base incentive award awarded during the year,
• · under the item "deferral period", the duration of the vesting period for the deferred incentive awards awarded in the year.

The column labelled "Bonus for previous years details":

• · under the item "no longer payable", the long-term incentive awards no longer payable in relation to verified performance conditions for the vesting period or incentives that expired due to events relating to employment relationships as envisaged in the Plan Rules,
• · under the item "payable," the deferred incentive accrued in the year, on the basis of verification of the performance conditions for the vesting period, or the incentive amounts earned due to events relating to employment relationships as envisaged in the Plan regulations:
• · under the item 'still deferred, incentives assigned in previous years that have not yet vested,

The column labelled "Other Bonuses" details incentives earned on a one-off extraordinary basis related to the achievement of particularly important results or projects during the year.

The total of the amounts under the item "payable" in the columns "Bonus for the year", "Bonus for previous years' and "Other Bonuses" is the same as that indicated in the "Bonuses and other incentives" column in table 1.

ANNEX

TABLE 2 - MONETARY INCENTIVE PLANS FOR THE CHIEF EXECUTIVE OFFICER AND CENERAL MANAGER, CHIEF OPERATING OFFICERS AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES (AMOUNTS IN EURO THOUSANDS)

				Bonus for the year			Bonus for previous years
Name and			payable/		deferral	no longer	payable/	31.01	Other
SUPPLATER	Position	Plan		paid deferred	petiod	payable		paid deferred	samusios
		2024 Short-Term Incentive Plan . Plan . Plan . Plan . 860 of March 13, 2024	2,184
		2024 Short-Term Incentive Plan - Portion deferred BoD of March 13, 2024		1,176	3 years
Claudio Descatri	Chief Executive Officer and General Manager	2023 Short-Term Incentive Plan · Portion deferred BoO of March 16, 2023						1,109
		2022 Short-Term Incentive Plan - Portion deferred BoD of March 17, 2022						1,134
		2021 Short-Term Incentive Plan - Portion deferred BoD of March 18, 2021					2330
Iptal			2,184	1,176			2,330	2,243
		2024 Short-Term Incentive Plan - Plan - Portion paid BoD of March 13, 2024	5754
	Chica Decrating	2024 Short-Term Incentive Plan . Portion deferred. Boo of March 13, 2024		3000
ිරියාන්‍ය BRIMOD	Officer · Natural Resources	2023 Short Term Incentive Plan - Portion deferred. BoO of March 16, 2023						330
	from 07/02/2022	2022 Short-Term Incentive Plan - Portion deferred BoO of March 17, 2022						210
		2021 Short-Term Incentive Plan - Portion deferred BoD of March 18, 2021					243
Total			075	309			243	540
		2024 Short-Term Incentive Plan - Plan - Portion paid BoD of March 13, 2024	25000
		2024 Short-Term Incentive Plan · Portion defened BoD of March 13, 2024		30101
Gius Epipe Richar	Chief Operating Officer Lnengy Lyolution	2023 Short Term Incentive Plan Portion deferred BoO of March 16, 2023						338
		2002 Short-Term Incentive Plan - Portion deferred BoD of March 17, 2022						304
		2021 Short-Term Incentive Plan - Portion deferred BoD of March 18, 2021					601
Total			259	301			601	642
		2024 Short-Term Incentive Plan - Portion paid BoD of March 13, 2024	7,64714)
		2024 Short-Term Incentive Plan · Portion deferred BoD of March 13, 2024		3,8022	3 years
Other Managers with Strategic		2023 Short Term Incentive Plan · Portion deferred BoO of March 16, 2023						3,794
Responsibilities		2027 Short-Term Incentive Plan - Portion deferred. BoD of March 17, 2022						3,404
		2021 Short-Term Incentive Plan - Portion deferred BoD of March 18, 2021					5,636
Total			7,647	3,802			2,636	7,198
			10,965	5,588			8,810	10,623

la kelastical in 2022 betell net 2021 betales includes (ander climation) and and the sepositive to and the states in and allesting on the september the mail and envis de ser

Table 3 - Incentive plans based on financial instruments, other than stock options, for the Chief Executive Officer and General Manager, Chief Operating Officers and Other Managers with Strategic Responsibilities

The table below shows, for the Long-Term Equity based Incentive Plan, the shares awarded/grantable to the Chief Executive Officer and General Manager and Chief Operating Officers, and, in terms of aggregate numbers, to the Other Managers with Strategic Responsibilities (including all individuals who covered such positions for any period of time during the year).

In particular:

• · the column "Financial instruments awarded in previous years and not vested during the year" shows the type, number and vesting period of any financial instruments awarded in previous years and not vet vested:
• · the column "Financial instruments awarded during the year" shows the type, number, total fair value, vesting period, award date, and market price on that date for financial instruments awarded during the year;
• · the column "Financial instruments vested during the year and not granted" shows the type and number of any financial instruments awarded and no longer grantable based on verification of performance during the vesting period, or of any financial instruments awarded and not grantable due to termination of employment as governed by the rules of the plans;
• · the column "Financial Instruments vested during the year and grantable" shows the type, number and value on the vesting date of any financial instruments awarded and vested during the year and grantable based on the verification of performance during the vesting period, or of the amounts provided for with regard to events concerning the employment relationship governed by the Plan Rules; in case of unavailability of the performance result at the date of approval of the Report, the table shows the estimate of the number of shares grantable in relation to the performances already venified and to hypotheses of target level for the performances not yet available at the date of publication of the Report:
• · the column "Financial instruments for the year" shows the fair value of the financial instruments awarded and still in existence solely for the portion pertaining to the year, which is also shown in table 1 in the column "Fair value of equity-based remuneration".

ANNEX

TABLE 3 - INCENTIVE PLANS BASED ON FINANCIAL INSTRUMENTS, OTHER THAN STOCK OPTIONS, FOR THE CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER, CHIEF OPERATING OFFICERS AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES

	surrame Position			Financial instruments awarded in previous years perpor not vested during the year	Financial instruments awarded during the year Market					Financial Instruments Vested during the year and not grantəd	Financial instruments vested during the year and grantable		Financial instruments for the year
Name வர்		Mars	Nurnber shares	of Ent Vesting period	Number of Eur התלמדים	Fair value at award ដងដែ	Vesting period	Award dato	price on award ปลูก ansal	Number of forvi til teams.	Number of Em נטומלה	Mailue at date of vesting	Fall VAUD
	Chef Executive	2023 Equity-based Long-Term Incentive Plan BoD October 26, 2023			173,109			2,439 3 years October 26, 2023	12918				147
Claudio Desnalzi	General Manager 85 Mom-	Officer and 2022 Equilly-based Long Term Incentive Plan BoD October 27, 7072	2007530	3 years									600
	May 9, 2014	2021 Equity-based Long-Term Incentive Plan BoD October 28, 2021								25,397	205,485H		824
Total					173,109	2,439				25,397			1,666
		Managers with strategic responsibilities
	Chief Operating Officer Natural Hesources	2073 Fquity-based Long-Term Incentive Plan BoD October 26, 2023			20248			3 9 years Novernber 30, 2022	14324				11
Guido BUSCU		2022 Equity-bosed Long-Tomm Incentive Plan BaD October 27, 2022 2071 Fquity-hased		30,950 3 years									119
		Long-Term Incentive Plan BOD OCTODER 28, 2017								1,952	15,797H		20
Total					29,248	389				1,925			189
		2023 Equity-based Long-Term Incentive Plan BoD October 26, 2028			28,453			379 3 years November 30, 2023	14324				11
QUARPIDE RICCI	Chief Operating Officer Encigy Evaillipou	2022 Equily based Long-Testin Incentive Plan BoD Octaber 27, 7072		31,772 3 years									127
		2027 Equity-based Long-Term INCENTRAS PHIN BoD October 28, 2021								3.646	20,495H		103
Total					28,455	379				3,646			242
		pased-family-pased Long-Term Incentive Plan BaD October 26, 2023			370816			4,935 J years November 30, 2023	14324
Other Managers with Strategic Responsibilities		2022 Equity based Long-Term Incentive Plan BoD October 27, 2022		373,265 3 years									1,438
		pasespyings i zoo Long-Telm Incentive Plan Bal) October 28, 2021									41,011 3318134		1,230
Responsibilities	Total Managers with Strategic				370,816	4,835				41,011			2,668
(with Civi)		Total Managers with Strategic Responsibilities			428,519	5,703				40,609			3.0aa
Grand total					601,628	8,142				72,006			4,765

(i) Norther frides france) station of the mails care the research on the clef be decide on the continues were consider of the contraction, only reported the Collective Direct executives).

SHAREHOLDINGS HELD

The table below reports, under article 84-quater, fourth paragraph, of the Consob Issuers Regulation, the shareholdings in Eni SpA and Its subsidialies that are held by Directors, Statutors and Other Managers with Strategic Responsibilities, as well as by their spouses from whom they are not legally segarated, and their children years of age, directly or through subsidiaries, trust companies, or internediaries, as recorded in the register of shareholders, communications received and other information sources. The table includes all parties who meet this description for all or part of the reporting period.

The number of shares (all "ordinary") is indicated, for each company held, by name, for Directors, Statutory Auditors and, at an aggregate level, for the Other Managers with Strategic Responsibilities. The individuals indicated hold title to the shareholdings.

TABLE 4 - SHAREHOLDINGS HELD BY DIRECTORS. STATUTORY AUDITORS. THE CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER, CHIEF OPERATING OFFICERS AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES [2023]

Name and surname	Position	Affiliated company	Number of shares held at 12:31:2022	Number of shares acquired in	Number of shares sold bo	Number of shares held at 12 31.2023
Board of Directors
Claudio Descalzi	Chief Executive Officier	Eni SpA	251,077	295,753	120.458	426,272
Chief Operating Officers
Guida Brusson	COO NR	Eri SpA	10,682	16,904	7,259	20.327
Giuseppe Ricci	COU EE	Eni SDA	26,952	37,052	13,764	50.240
Other Managers with Strategic Responsibilities ==		En SDA	382,451	502,358	268,777	616032

(all noluting the assignment of the 2020 award of the LI I Share into LI I Share into in 2020 2022.

It in the fine of the may and its to to the souponse the 2020 multine thing the Qualing Olice, Die Quarter Dities, Die Questing Olizes on version in the Chel Desire Dites, Di executives, all of which with shareholdings in Eni SpA).

ANNEX 61

ANNEXED UNDER ARTICLE 84-BIS OF CONSOB ISSUER REGULATION - 2023 IMPLEMENTATION OF THE 2023-2025 LONG-TERM INCENTIVE (LTI) PLAN

With reference to the 2023-2025 Long-Term Equity-based Incentive Plan approved by the ordinary Shareholders' Meeting on May 10, 2023, subject to the conditions and purposes set out in the information Document available on the website, the following table shows details of 2023 Plan award, in accordance with Art. 84 bis (Annex 3A, schedule 7) of the CONSOB Issuer Regulation.

TABLE NO. 1 OF SCHEDULE 7 OF ANNEX 3A OF REGULATION NO. 11971/1999

					FRAME 1
				FINANCIAL INSTRUMENTS OTHER THAN STOCK OPTIONS
					Section 2
		Newly assigned instruments based on the decision of the body in charge of the implementation of the resolution of the Shareholders' Meeting
Name an surname or category	Position (to be specified only for individuals listed by name)	Date of shareholders' resolution	Type of financial Instruments	Number of financial Instruments	Award date	Purchase price of the Instruments.	Market price at the time of award (Grad)	Vesting period
Caludio Descalzi	CEO and General Manager Eni SpA	Nay 10, 2023	Erii stiares	173,109	26/10/23	11.2	15.442	3 years
Luca Albumo	CEO Raffinena Di Gela SpA	May 10, 2023	Eni shares		2705 30/11/23	na	15.168	3 years
Adriano Alfani	CEO Versalis SpA	May 10, 2023	Eni shares		23.442 30/11/23	n.a.	15.168	3 years
Clara Andreals's	Chairwaman & CEO . Eni Next LLC	Moy 10, 2023	Eni shares		2344 30/11/23	n.u.	17 169	3 years
Mirke Araldi	Directeur Gisneral Eril Congo SA	Moy 10, 2023	Eni stiarcs		2,128 30/11/23	no	15.168	3 years
Andres Ralascroni	Managing (Ilrector Versalis Singapore I tri	May 10, 2023	Fill shares		7,200 30/11/23	n.a.	15 168	3 years
Antonio Massirriliano Baldassarra	General Manager Eni North Africa BV	May 10, 2023	Eni shares		3.787 30/11/23	n.a.	12 108	3 years
Sistano Ballista	Chairman and CEO Eni Sustamable Mobility SpA	May 10, 2023	SBIETIES ILG		13:272 30/11/23	成立	15.168	3 years
Marco Vittorio Bollini	Managing Director Eni International BV	May 10, 2023	Eni shares		7,321 30/11/23	11.8	15.168	3 years
Fobrizio Bolondi	Managing Director Naoc Ltd	May 10, 2023	Eni shares		2,813 30/11/23	FLO.	12:168	3 years
Alberto Mario Bonnthini	Managing Director Eni International Resources Ltd.	May 10, 2023	Ern shares		6,536 30/11/23	n.a.	15,168	3 years
Manca Calabrese	Managing Dinector & General Manager Ern Rowuma Basin DV	May 10, 2023	Eni shares		1,947 30/11/23	na	32.168	3 years
Mallu Camgarati	General Manager leac Production BV	May 10, 2023	Ers shares		3751 30/11/23	ru	12.168	3 years
Francesco Carla	CFO Seacomdor Srf	May 10, 2023	Eni shares		4,003 30/11/23	0.8	15 168	3 years
Paolo Camerale	President & CEO Eni Trading & Shipping Inc.	May 10, 2023	Eni shares		3,282 30/11/23	0.21	15.168	3 years
I mano Colombo	CEO Eni Corporate University SpA	May 10, 2023	Em shares		4,977 30/11/23	ri. 28.	12:200	3 years
Roberto Daniele	Managing Director Muara Bakau BV	May 10, 2023	Eni shares		4,147 30/11/23	n.a.	15.168	3 years
Paglo De Julia	CEO Eni Suisse SA	May 10, 2023	EU SUBLES		2.200 30/11/23	urg	12.163	3 years
Antonio De Roma	CEO Eur BIOCHAIN SPA	May 10, 2023	Eni shares		2.74T 30/11/23	n.a.	15.168	3 years
Alessandro Gaeta	CEO Eni Trade & Biofuels SpA	May 10, 2023	Eni shares		4,364 30/11/23	ne	12.168	3 years
Messandro Gelmetti	Managing Director Eni Vietnam BV	May 10, 2023	En shares		2,416 30/11/23	n.m.	15,168	3 Mars
Gabriele Giona	Managing Director & General Manager Petrobel Belaym Co.	May 10, 2023	Eni shares		2.164 30/11/23	na	12.168	3 years
Paolo Grossi	CEO Eni Rewind SpA	May 10, 2023	En shares		10.423 30/11/23	na	15.168	3 years
Giovanni Grugni	Chairman and CEO Floaters	May 10, 2023	Eni shares		2,669 30/11/23	0.8	12:168	3 years
QUADIO GUIQI	Managing Director Eni Mexico Sricy	May 10, 2023	En shares		3,210 30/11/23	n.a.	15.168	3 years
Massimo Mana Insula	President and CEO - GM Eni US Op. Inc.	May 10, 2023	En shares		3,570 30/11/23	0.8	15.168	3 years
Maurizio Limiti	Managing Director Eni Espana Comercializadora De Gas SAU	May 10, 2023	Eni shares		1,803 30/11/23	作品	15.168	3 years
Giuseppe La Fiaso	Managing Director Versalis Deutschland GmbH	May 10, 2023	Eni shares		1,659 30/11/23	fi.a.	12.168	3 years

[a] Kumber of attares awarded with roos lution of the Board of Directors of Dictober 26, 2023.

TABLE NO. 1 OF SCHEDULE 7 OF ANNEX 3A OF REGULATION NO. 11971/1999

					FRAME I
		FINANCIAL INSTRUMENTS OTHER THAN STOCK OPTIONS
				Section 2
		Newly assigned instruments based on the decision of the body in charge of the implementation of the resolution of the Shareholders' Meeting
Name an curname or category	Position (to be specified only for individuals listed by name)	Date of shareholders' resolution	Type of financial Instruments	Number of financial Instruments	Award date	Purchase price of the instruments	Market price at the time of award (euro)	Vesting periad
Sergio Francantonio	Chairman & Managing Director Versalis International SA	New 10, 2023	Eni shares		5,662 30/11/23	11,51	12.168	S years
Lomberdini Giuseppe Macchia	CEO AGI Agenzia Giornalistica Italia SpA	May 10, 2023	Eni shares		4,039 30/11/23	na	12.148	s years
Alberto Manzati	Managing Director Enl Iraq BV	May 10, 2023	Eni shares		1947 30/11/23	na	12.169	3 years
Renato Maroli	Managing Director And Resident Manager Agip	May 10, 2023	Eni shares		3.823 30/11/23	n.a.	15.168	3 years
Nicola Mavilla	Karachaganak BV Managing Director Em Colle Divoire Lid	2202 10, 2023	Eni shares		2.921 30/11/23	11.21	15,168	3 years
Adriano Mongini	Chief Executive Official Azale Energy Angola BV	May 10, 2023	Surfright 109		8.692 30/11/23	na	15.168	3 ਮੌਤੀ 2
Giuseppe Moscato	Managing Director Ent Miaroc BV		Eni shares		4,147 30/11/23	08	12.168
		May 10, 2023						3 years
Annalisa Muccioli	CEO Eniprogetti SpA	May 10, 2023	Eni shares		2.272 30/11/23	18	12 168	3 years
Altonso Pagano	General Manager Coral FLNG SA	Nal 16, 2023	Eni shares		2,408 30/11/23	11, 31	12.108	3 years
Denis Palemo	Managing Director Eni Australia Ltd.	May 10, 2023	Eni shores		2.488 30/11/23	na	12.168	3 years
Remo Pasquali	Chairman and CEO Eni Sustainable Mobility US Inc.	May 10, 2023	En shares		4,833 30/11/23	12.28.	15.168	Sycars
Andres Parcivalia	CEO/GM Eni Funi SpA	May 10, 2023	Eni shares		6.131 30/11/23	日本	15.168	3 years
Marco Petracchini	Chairman Versalis SipA	May 10, 2023	Eni shares		10,350 30/11/23	n.a.	12 168	s years
Blagio Pietraroia	Managing Director Eni Oman UV	May 10, 2023	Eni shares		3.282 30/11/23	na	12.168	3 years
Luciono Piliari	CEO Eni Doutschland GmbH	May 10, 2023	Eni shares		2.921 30/11/23	n.ü.	12.168	3 years
Alina Pomar	Chairwoman and CEO Enimed SpA	May 10, 2023	Eni shares		1,587 30/11/23	n.u.	12.168	3 years
Diego Portoghese	Managing Director Eni Sharjha BV	May 10, 2023	Em shares		3,859 30/11/23	ri, its.	12 168	3 years
Paolo Repelli	CFO Eniservizi SpA	Way 10, 3023	Eni shares		5.518 30/11/23	11.8	18.108	Syears
Federico Rey	Managing Director Banque Eni SA	May 10, 2023	Eni shares		3.043 30/11/23	na	15.166	3 years
Alessandro Rosatelli	Managing Director Eni Abu Dhabi Refining & Trading Services BV	May 10, 2023	Eni shares		2341 30/11/23	na	32.109	3 years
Giancano Ruiu	General Director Karachaganak Petroleum Operating BV	May 10, 2023	Eni shares		2.380 30/11/23	18.5	15.168	3 years
Glovanni Sabat ini	CEO Eni Ecuador SA	May 10, 2023	Eni shares		2.236 30/11/23	n.a.	15.168	Syears
Fullio Sintlo	General Manager Zenith SA	May 10, 2023	Eni shares		4,003 30/11/73	n.a.	15.168	3 years
Ferruccio Taverna	General Manager Damietta LNG Services SAE	May 10, 2023	Eni shares		2236 30/11/23	0.8	12.108	3 years
Giorgio Tuccio	Chainman Versalis France SAS	May 10, 2023	Eni shares	3.354	30/11/23	n.a.	15.168	3 years
Tamas Varga	Chairman & Managing Director Dunastyr Polystyrene Manufacturing Co Ltd.	May 10, 2023	Eni shares	1,726	30/11/23	n.a.	15.168	3 years
	Luciano Mania Vasques Managing Director Eni Uk Ltd.	May 10, 2023	Eni shares		4,003 30/11/23	n.a.	15.168	3 years
Maurizio Vecchiola	Chairman and CEO Finproject SpA	May 10, 2023	Eni shares		6.492 30/11/23	na	11:168	ર પ્રદેશ દ
Giorgio Vicini	Directeur General Eni Algeria Production BV	May 10, 2023	Eni shares		2,741 30/11/22	12.8	12 168	3 years
Other Eni Managers Oldağılırsı Kılıstan Responsibilities to	21 managers	May 10, 2023	Eni shares		371.032 33/11/23	0.8	15.168	3 years
Other Managers	SWIT managers.	May 10, 2023	Eni shares		1,127,216 30/11/23	urg	15,168	3 years

If the beather who at time of evel evel the Chef Eleculte Offices we Chel Opealing Offices wee personed the Corpory s Masogerers Damintee or reported bectly the CO.

ANNEX

Annex: list of charts and tables

LIST OF CHARTS

Charl		Total Shareholder Return	್ರಾ
Chart		2 Total Recordable Injury Rate (TRIR) and Severity Incident Rate (SIR)	ಿಡ
Charl		3 NET GHG Emissions Upstream Scope I and 2 equity and GHG emission intensity Scope 7 and Scope 2 Upstream equity 10
Charl	4	Total average remuneration 2023	10
Chart	5	Pay for performance analysis.	11
Chart		6 . Results of shareholders' vote on Eni Remuneration Report in 2017-2023 - Section I	18
Charl		7 - Results of shareholders' vote on Eni Remuneration Report in 2020-2023 - Section III	19
Chart	8	Fotal Incentive Multiplier	33
Chart	0	Defenred incentive - timeline	33
Chart	10	Defenred incentive multiplier	34
Chart	11	Equity-based LTI Plan timeline	34 (1)
Chart		12 Performance acale - multiplier for absolute parameters.	37
Chart	33	Pay mix CEO	38
Chart	ને ની	Pay mox MSRs	40

LIST OF TABLES

Table	1 1	CEO/GM pay ratio vs. median employee temuneration	11
Table	12	Raw gender cray ratio	12
Toble	ത	Gender pay ratio with equal roles and servority	12
able	4	Minimam wages	13
latie	U	Alignment with the strategic plan	15
Table	6	Our governance practices	35
Intie	7	2024 Riemuneration Policy summary	36
Table		8 Remuneration Committee meetings in 2023	23
Taure		9: Annual cycle of Remaneration Committee activities	24
Tacle		10 New CEO remuneration Peer Group	28
luble		11 2024 targets for the Short-Term Incentive Plan with deferral 2025	31
1900		12 Levels of annual payable incentive	33
lable		13 Levels of payable deferred partion	34
Tistie		14 Absolute 2024-2026 targets for the 2024 award of the 2023-2025 1T1 share based plan	રેતું
Tacle		15 Performance Scale - Relative Performance Scale Multiplier (Tsr)	રેજે
Fable		16 Value levels of granted shares	37
Table		17 Remuneration paid to the CEO/GM in 2019-2023.	43
Balle		18 Remuneration paid to the Chief Operating Officer - Natural Resources in 2020-2023	43
Fable		19 Remaneration paid to the Chief Operating Officer - Energy Evolution in 2020-2023	44
Table		20 Verification of 2023 objectives	45
lable		21 Final multiplies of the stildefened portion accrued in 2021-2023	46
able		22 Summary of remuneration accrued for the CEO/GM in 2023	48
Table		23 Summary of remuneration accrued for the Chief Operating Officer . Natural Resources in 2023	50
Table		24 Summary of remuneration accued for the Chief Operating Officer . Energy Evolution in 2023	ದರಿ
Table		25 Firal equity based it plan 2020 multiplier accrued in 2020-2022.	21

LIST OF CONSOB TABLES

NYC	Temureration paid to directors, statultors, the chief executive officer and general manager and other managers with strategic responsibilitys.	54
Tacie	Monetary incentive plans for the Chief Executive Officer and General Manager, Chief Oberating Officers; and Other Managers with Strategic Responsibilities	57-
Table	incentive piens based on financial instruments, other than stock contines, for the Chief Executive Officer and General Manager, Chief Operating Officers and Other Managers with Strategic Responsibilities.	59 :
Taller	Shareholdings held by Directors, Statutory Auditors, the Chief Executive Officer and General Manager, Chief Operating Officers and Other Managers with Strategic Responsibilities	60 -
	Table N.1 Table No. 1 of Schedule 7 of Annex 3A of Requisition No. 11971/1999	61.

Eni SpA

Headquarters

Piazzale Enrico Mattei, 1 - Rome - Italy Capital Stock as of December 31, 2023. € 4,005,358,876.00 fully paid Tax Identification number 00484960588

Branches

Via Emilia, 1 - San Donato Milanese (Milan) - Italy Piazza Ezio Vanoni, 1 - San Donato Milanese (Milan) - Italy

Contacts

enicom +39 0659621 800940924 sogretoriasocietaria azionisti@eni.com

Investor Relations

Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-02520.51651 - Гах +39-0252031929 e-mail investor.relations@omicom

Layout and supervision K-Change - Rome

Eni S.p.A.

Estimated

Future Reserves and Income

Attributable to Certain Interests

SEC Parameters

As of December 31, 2023

Daniel R. Olds, P.E. TBPELS License No. 60996 Managing Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPELS REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191

March 1, 2024

Eni S.p.A Mr. Alessandro Tiani Head of Reserves Via Emilia 1 20097 San Donato Milanese Milano, Italy

Dear Mr. Tiani:

At the request of Eni S.p.A. (Eni), Ryder Scott Company, L.P (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni's engineering and geological staff as of December 31, 2023 based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 31, 2024 and presented herein, was prepared for public disclosure by Eni in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Eni has indicated that the proved net reserves attributable to the properties that we reviewed account for 23.0 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following three geographic locations:

• Africa
• Italy
• Asia

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as "the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information." Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by Eni, it is our opinion that the overall procedures and methodologies utilized by Eni in preparing their estimates of the proved reserves as of December 31, 2023 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott's estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Eni in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799
633 17TH STREET, SUITE 1700	DENVER, COLORADO 80202	TEL (303) 339-8110

Page 2

The conclusions discussed in this report are related to hydrocarbon prices. Eni has informed us that in preparation of their reserves and income projections, as of December 31, 2023, they used average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-themonth for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "PETROLEUM RESERVES DEFINITIONS" is included as an attachment to this report.

The various proved reserves status categories are defined in the attachment entitled "PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES" in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein.

Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni's request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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." The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered."

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni's representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni derives an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely to be achieved than not." The SEC states that "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." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by Eni, for the properties included herein were estimated by performance methods, material balance, analogy methods, the volumetric method, or a combination of performance, material balance, and volumetric methods. These performance methods include, but may not be limited to, decline curve analysis, volumetric, material balance and analogy which utilized extrapolations of historical production and pressure data available through October 2023 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Eni and were considered sufficient for the purpose thereof. The volumetric method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Eni that were available through October 2023. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or contract areas, other costs such as transportation and/or processing fees and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Eni. We consider the factual data used in this report appropriate and sufficient for the purpose of our investigations.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to conduct the audit of reserves of the properties described herein. The proved reserves discussed herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves reviewed in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Eni. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Hydrocarbon Prices

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Eni relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by ENI for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the- month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Eni furnished us with the above mentioned average prices in effect on December 31, 2023. Eni has assured us that these initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. The average dated Brent oil price of \$83.27/bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. The average realized prices provided by Eni for the properties reviewed by us are as follows:

Geographic Area	Product	Average Proved
		Realized Prices
	Oil	\$83.22/bbl
Africa	Condensate	\$65.02/bbl
	Gas	\$7.01/Mcf
	Oil	\$54.36/bbl
Italy	Condensate	N/A
	Gas	\$11.04/Mcf
	Oil	\$80.37/bbl
Asia	Condensate	\$65.72/bbl
	Gas	\$0.53/Mcf

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Eni. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Eni to determine these differentials.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Costs

Operating costs furnished by Eni for the properties reviewed by us were based on the operating expense reports of Eni and include only those costs directly applicable to the reviewed assets. The operating costs include a portion of general and administrative costs allocated directly to the contract areas and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Eni. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets.

Development costs were furnished to us by Eni and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Eni were accepted without independent verification.

The proved developed and undeveloped reserves in this report have been incorporated herein in accordance with Eni's plans to develop these reserves as of December 31, 2023. The implementation of Eni's development plans as presented to us and incorporated herein is subject to the approval process adopted by Eni's management. As the result of our inquires during the course of preparing this report, Eni has informed us that the development activities included herein have been subjected to and received the internal approvals required by Eni's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Eni. Eni has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Eni has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2023, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Eni were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Eni. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Eni.

We have provided Eni with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Eni and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L. P.

TBPELS Firm Registration No. F-1580

Daniel R. Olds, P.E. TBPELS License No. 60996 Managing Senior Vice President

DRO (HGA)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Daniel R. Olds was the primary technical person responsible for overseeing the estimate of the reserves, future production, and income prepared by Ryder Scott presented herein.

Mr. Olds, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2001, is a Managing Senior Vice President and also serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. He is a member of Ryder Scott's Board of Directors. Before joining Ryder Scott, Mr. Olds served in a number of engineering and evaluation positions with PricewaterhouseCoopers, Wintershall Oil and Gas Company and Cities Service Oil Company. For more information regarding Mr. Olds' geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Employees.

Mr. Olds earned a Bachelor of Science degree in Petroleum Engineering from West Virginia University in 1981, an MBA from the University of Houston in 1991 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Evaluation Engineers (past president) and the Society of Petroleum Engineers. He currently serves on the SPE Oil and Gas Reserves Committee.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Olds fulfills. For 2023, Mr. Olds has 29 continuing education hours related to reserves, reserve evaluation, and ethics.

Based on his educational background, professional training and 40 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Olds has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the "Modernization of Oil and Gas Reporting; Final Rule" in the Federal Register of National Archives and Records Administration (NARA). The "Modernization of Oil and Gas Reporting; Final Rule" includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The "Modernization of Oil and Gas Reporting; Final Rule", including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the "SEC regulations". The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4- 10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

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. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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 legal right to 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.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE) WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA) EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4- 10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further subclassified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

• (1) completion intervals that are open at the time of the estimate but which have not yet started producing;
• (2) wells which were shut-in for market conditions or pipeline connections; or
• (3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

March 4, 2024

Alessandro Tiania Head of Reserves

Eni S.p.A. Via Emilia, 1 20097 San Donato Milanese Italy

Dear Mr. Alessandro Tiani,

Sproule International Limited ("Sproule") has been engaged by Eni S.p.A. ("ENI" or the "Company") to evaluate the Proved reserves in Europe, as of December 31, 2023, and to prepare a report as to its findings (the "Report"). This evaluation was completed on March 1, 2024. ENI has represented that these properties account for 1 percent of ENI's net proved reserves as of December 31, 2023, on an oil equivalent barrel basis.

The net proved reserves estimates were prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures and methodologies employed by ENI for the preparation of its proved reserves estimates as of December 31, 2023, comply with the current requirements of the SEC. We have reviewed information provided by ENI that it represents to be ENI's estimates of the net reserves, as of December 31, 2023, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by ENI.

Reserves estimates presented in this certification letter are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated hydrocarbon remaining to be produced from these properties after December 31, 2023. Net reserves are defined as the portion of gross reserves attributable to the interests held by ENI after the deduction of royalties. The accuracy of reserves estimates and associated economic analysis is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. Given the data provided at the time this report was prepared, the estimates presented herein are considered reasonable.

Information used in the preparation of this certification letter was obtained from ENI. In the preparation of this certification letter we have relied upon information furnished by ENI with respect to the evaluated property interests and burdens, production from such properties, relevant production and analytical tests performed in such properties, relevant geoscience data such as logs and analytical reports, current costs of operation and development, future capital costs for development, future costs for abandonment and reclamation in compliance with local abandonment and reclamation requirements, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented.

In the preparation of this evaluation, field inspections of the properties were not performed. No material information regarding the reserves evaluation would have been obtained by an on-site visit.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as below (from Regulation S-X):

Proved Oil and Gas 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.

• i. The area of the reservoir considered as proved includes:
  • a. The area identified by drilling and limited by fluid contacts, if any, and
  • b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
• ii. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
• iii. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
• iv. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
  • a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
  • b. The project has been approved for development by all necessary parties and entities, including governmental entities.
• v. 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.
  • 2

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

• i. 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
• ii. Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves

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.

• i. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
• ii. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years unless the specific circumstances justify a longer time.
• iii. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019" and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by ENI, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimated herein were based on opportunities identified in the development plan provided by ENI.

ENI has represented that its senior management is committed to the development plan provided by ENI and that ENI has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

The technically recoverable oil and natural gas resources were estimated volumetrically, using analogy techniques, or by decline analysis. Volumetric reserves were estimated using the geological models constructed by ENI using a commercial geomodel software. Reservoir rock and fluid property data were obtained from well logs, PVT data and gas analyses either from the pool in question or from a similar reservoir producing from the same zone. Reservoir pressures were derived from drillstem and AOF test data and pressure surveys. Recovery factors for technically recoverable resources were selected from the results of analytical reservoir analyses, or by comparing the reservoir under study with similar reservoirs that have more firmly established recovery factors from extended production histories.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. In all cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available and provided by ENI. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. Plant liquids volumes estimated herein include propane, butane, and pentanes and heavier fractions (C5+). Plant liquids volumes are the result of lowtemperature plant processing.

Oil, condensate, and plant liquids volumes reported herein are expressed in thousands of barrels (10³ bbl). Gas quantities estimated herein are expressed as natural gas, sales gas, and dry gas. Natural gas is the total gas produced from the reservoirs prior to processing or separation and includes all nonhydrocarbon components.

Sales gas is defined as the total gas to be produced from the reservoirs, measured at the inlet of the processing plant, after reduction for injection, fuel usage, flare, and shrinkage resulting from field separation. Dry gas is defined as the total gas to be produced from the reservoirs, measured at the tailgate of the processing plant, after reduction for injection, fuel usage, flare, and shrinkage resulting from field separation and plant processing. Gas reserves estimated herein are reported as sales gas.

Gas quantities estimated herein are expressed at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1 atmosphere (atm). Gas quantities presented in this certification letter are expressed in millions of cubic metres (10⁶m3). Gas quantities are identified by the type of reservoir from which the gas will be produced. Non-associated gas is gas at initial reservoir conditions with no crude oil present in the reservoir.

Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying crude oil zone. Solution gas is gas dissolved in crude oil at initial reservoir conditions. Gas quantities estimated herein include both associated and Non associated gas.

At the request of ENI, gas quantities estimated herein were converted to dry gas equivalent to liquids using an energy equivalent factor as provided by ENI.

ENI has represented that the development activities provided and evaluated herein were internally approved.

Development activities provided by ENI are scheduled to initiate within 5 years of the effective date of the Report (December 31, 2023) for activities associated with Proved undeveloped reserves.

The oil and natural gas reserves were estimated based on the technically recoverable resources, operating and capital costs and the terms of the fiscal regime. Forecasts of net revenue were prepared by predicting the annual production from the reserves, and ENI provided product prices.

The technically recoverable condensate resources were estimated based on estimates of future gas production and future condensate recovery provided by ENI. Annual production was forecast taking into account well deliverability, the status of reservoir depletion, applicable regulatory conditions, and by comparison with other wells in the vicinity producing from similar reservoirs when available.

Gas reserves have been assigned based on confirmation from ENI that there is a market to produce to. The expense has been included in the cash flows for the use of fuel gas.

Solution gas reserves have been assigned based on confirmation from ENI that there is a market to produce for. The expenses for the use of fuel gas have been included in the costs provided by ENI.

The price forecasts that formed the basis for the revenue projections in the evaluation were based on the constant prices provided by ENI at December 31, 2023.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by ENI in United Kingdom pounds sterling (£). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Product Prices

ENI has represented that the oil, condensate and gas prices were based on a reference price, 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, unless prices are defined by contractual agreements. The prices were not escalated for inflation.

Location	Average Gas Price USD/103 ft3	Average Oil Price USD/bbl	Average Condensate Price USD/bbl
Europe	13.9	84.6	53.6

Operating Expenses, Capital Costs, and Abandonment Costs

The operating costs and capital costs used in the evaluation were provided by ENI. Estimates of operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the developed nonproducing and the undeveloped reserves estimated herein.

The abandonment, decommissioning and reclamation ("ADR") costs associated with ENI's hydrocarbon exploration, development, production and processing operations in the property of interest were included in this report. ENI provided estimates of the ADR costs associated with their hydrocarbon exploration, development, production and processing operations, for inclusion in this evaluation of their hydrocarbon assets data and were accepted as represented.

Guidance

In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932- 235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a)(1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC.

Summary of Conclusions

ENI has represented that its estimated net Proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC.

In comparing the detailed net Proved reserves estimates prepared by Sproule and ENI, differences have been found, both positive and negative, resulting in an aggregate difference of 5 percent for Proved reserves when compared on the basis of net oil equivalent barrels. It is Sproule opinion that the net Proved reserves estimates prepared by ENI on the properties evaluated and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2023 estimated reserves.

Sproule possesses the technical skills and certifications required for this type of work. Sproule is a member in good standing of the Association of Professional Engineers and Geoscientists of Alberta ("APEGA"), an independent regulatory body that governs the practice of engineering and geoscience in the province of Alberta, Canada.

Sproule is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1951. Sproule does not have interest, direct or indirect, nor expects to receive any interest, direct or indirect, in the properties described in the report or in the securities of ENI. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of ENI. Sproule has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Yours truly,

Sproule International Limited

Doug Ashton, P.Eng. Doug Ashton, P.Eng. Vice President, Reservoir Services VP, Reservoir Services

Certificate of Qualification

Doug Ashton, P.Eng.

I, Doug Ashton, Vice President, Reservoir Services of Sproule, 900, 140 Fourth Avenue SW, Calgary, Alberta, declare the following:

• 1. I hold the following degree: a. B.Sc. Chemical Engineering (1992), University of Calgary, Calgary, AB, Canada
• 1. I am a registered Professional:

• a. Professional Engineer (P.Eng.), Province of Alberta, Canada

• 1. I am a member of the following professional organizations:
  2. a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)
  3. b. Society of Petroleum Evaluation Engineers (SPEE)
  4. c. Society of Petroleum Engineers (SPE)
• 1. I am a qualified reserves evaluator and reserves auditor as defined in:
  2. a. the "Canadian Oil and Gas Evaluation Handbook" as promulgated by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and,
  3. b. the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" as promulgated by the Society of Petroleum Engineers and incorporated into the "Petroleum Resource Management System" (SPE-PRMS).
• 1. My contribution to the work related to the attached third party letter is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non- confidential files of Sproule.
• 1. I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Eni S.p.A.

Sproule International Limited

Doug Ashton, P.Eng. Doug Ashton, P.Eng. VP, Reservoir Services

DEGOLYER AND MACNAUGHTON

500 | SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

This is a digital representation of a DeGolyer and MacNaughton report.

This file is intended to be a manifestation of certain data in the subject report and as such is subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DEGOLYER AND MACNAUGHTON

500 | SPRING VALLEY ROAD SUITE 800 EAST DALLAS, TEXAS 75244

March 11, 2024

Mr. Alessandro Tiani Head of Reserves Eni S.p.A. Via Emilia 1 20097 San Donato Milanese Italia

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the extent of the estimated net proved oil, condensate, liquefied petroleum gas (LPG), and gas reserves of certain properties in which Eni S.p.A. (Eni) has represented it holds an interest through its 50.00-percent corporate ownership of Azule Energy S.p.A. This evaluation was completed on March 11, 2024. The properties evaluated herein consist of working interests located offshore Angola (Table 1). Eni has represented that these properties account for 3.7 percent on a net equivalent barrel basis of Eni's net proved reserves as of December 31, 2023, and that Eni's net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures and methodologies employed by Eni for the preparation of its proved reserves estimates as of December 31, 2023, comply with the current requirements of the SEC. We have reviewed information provided to us by Eni that it represents to be Eni's estimates of the net reserves, as of December 31, 2023, for the same properties as those which we have independently evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Eni.

Reserves estimated herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Eni after deducting all interests held by others.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was provided by or on behalf of Eni. In the preparation of this report we have relied, without independent verification, upon information furnished by or on behalf of Eni with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) 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.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by or on behalf of Eni, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

The proved undeveloped reserves estimates were based on opportunities identified in the plans of development provided by or on behalf of Eni.

Eni has represented that it has confirmed through its corporate ownership that the operator is committed to the development plans provided by or on behalf of Eni and that the operator has the financial capability to execute the development plans, including the drilling and completion of wells and the installation of equipment and facilities.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.

When applicable, estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, other engineering methods were used to estimate recovery factors based on analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in productio-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined in the Definition of Reserves section of this report, or to the expiration of the production agreement, whichever occurred first. In the estimation of reserves, the current production license limits (including known extensions, as described herein) for each license were applied.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

In certain fields, a review was made of reservoir simulation studies performed by Eni. The available data related to future field development were also examined.

Data provided by or on behalf of Eni from wells drilled through December 31, 2023, and made available for this evaluation were used to prepare the reserves estimates herein. The reserves estimates were based on consideration of monthly production data available for certain properties only through August 2023. Estimated cumulative production, as of December 31, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 4 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. LPG reserves estimated herein consist primarily of propane and butane fractions and are the result of low-temperature plant processing. Oil, condensate, and LPG reserves included in this report are expressed in millions of barrels (10⁶bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil, condensate, and LPG reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas and fuel gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Gas reserves estimated herein are reported as marketable gas reserves; therefore, fuel gas is included as reserves. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in billions of cubic feet (10⁹ ft3 ).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein consist of both associated and nonassociated gas.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by or on behalf of Eni in United States dollars (U.S.\$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Oil, Condensate, LPG, and Gas Prices

Prices were furnished for each field and were held constant for the remaining producing lives of the fields. The oil, condensate, LPG, and gas prices provided were represented to be based on a reference price for each contract area, 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, unless prices are defined by contractual agreements. The Brent marker price for the period was U.S.\$83.27 per barrel, and the Title Transfer Facility reference gas price for the period was U.S.\$13.42 per thousand cubic feet. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were U.S.\$82.58 per barrel of oil, U.S.\$60.06 per barrel of condensate, U.S.\$23.39 per barrel of LPG, and U.S.\$2.60 per thousand cubic feet of sales gas.

Operating Expenses, Capital Costs, and Abandonment Costs

Operating expenses and capital costs were estimated based on information provided by or on behalf of Eni and referenced to existing economic conditions. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Future capital expenditures were estimated using current capital cost forecasts provided by Eni and were not adjusted for inflation. Certain capital cost forecasts include contractual spending as and when agreed. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were estimated using information provided by or on behalf of Eni and were not adjusted for inflation. In the case of undeveloped reserves, incremental abandonment costs were considered in the estimates. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

Fiscal Terms and Host Country Taxes

The properties evaluated in this report are in certain defined contract areas, which are groups of fields within an area governed by a specific agreement with the government of Angola. Host country taxes, where applicable, are taxes paid to the government of Angola. The economic models used in this report were constructed based upon the fiscal terms applicable to these contract areas. Projections of estimated production,operating expenses, and capital costs were summed for each field within each of the contract areas. These summed projections were used as input into the economic model.

In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

Eni has represented that its estimated net proved reserves attributable to its 50.00-percent corporate ownership of Azule Energy S.p.A. were based on the definitions of proved reserves of the SEC.

Eni has represented that its estimated net proved reserves, as of December 31, 2023, attributable to its ownership in Azule Energy S.p.A., which represent 3.7 percent of Eni's net reserves, are summarized as follows, expressed in millions of barrels (10⁶bbl) and billions of cubic feet (10⁹ ft3 ):

Estimated by Eni

Net Proved Reserves

		as of December 31, 2023 Marketable Gas Oil,Condensate, and
	LPG (106bbl)	(109ft3)
Total Proved	186	255

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by Eni, the aggregate difference has been found to be less than 5 percent. It is DeGolyer and MacNaughton's opinion that the net proved reserves estimates prepared by Eni on the properties evaluated and referred to above do not differ materially from those estimated by DeGolyer and MacNaughton.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2023, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716

Regnald A. Boles, P.E. Executive Vice President DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Regnald A. Boles, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

• 1. That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Eni dated March 11, 2024, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.
• 1. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1983; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, and the European Association of Geoscientist & Engineers; and that I have more than 40 years of experience in oil and gas reservoir studies and evaluations.

Regnald A. Boles, P.E. Executive Vice President DeGolyer and MacNaughton

Block	Block	Block
Area	Area	Area
Field	Field	Field
Block 0	Block 14	Block 17
Area A&B	BBLT	Clov
Banzala	Belize	Cravo
Bomboco	Belize North	Lirio
Cabinda A LPG	Benguela	O11W
Cabinda B LPG	Benguela North	OVM
Kokongo	Lobito	Dalia
Kungulo	Tomboco	Dalia
Limba	TL	Manganes
Limba SW	Landana	Tulipa
Lomba	Landana North	Girassol
Mafumeira	Tombua	Girassol-Jasmin
Malongo North		Rosa
Malongo West	Block 14K	Paz Flor
Nemba	Lianzi	Acacia
North N'dola	Lianzi	Perpetua-Hortensia
Nsano		Zinia
Nsinga	Block 15
Numbi	Kizomba A	Block 18
Sanha	Chocalho	Greater Plutonio
Takula	Hungo	Cobalto
Vuko	Marimba	Cromio
Wamba	Kizomba B	Galio
Lifua	Bavuca	Paladio
Lifua	Clochas	Platina
South N'dola	Dikanza	Plutonio
South N'dola	Kakocha
	Kissanje	Block 31
Block 1&2 - NGC	Mavacola	PAJ
1&2 - NGC	Mondo	Astraea
Maboqueiro	Mondo	Juno
Quiluma	Mondo South	Palas
	Saxi-Batuque	PVSM
Block 3/05	Batuque	Marte
3/05	Saxi	Plutao
Bufalo		Saturno
Cobo	Block 15/06	Venus
Impala SE	East Hub
Oombo	Cabaca North
Pacassa	Cabaca SE
Palanca	Cuica
Pambi	UM 45
3/05A	West Hub
Caco	Agogo
Gazela	Mpungi
Punja

DEGOLYER AND MACNAUGHTON 500 | SPRING VALLEY ROAD SUITE 800 EAST DALLAS, TEXAS 75244

This is a digital representation of a DeGolyer and MacNaughton report.

This file is intended to be a manifestation of certain data in the subject report and as such is subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DEGOLYER AND MACNAUGHTON 500 | SPRING VALLEY ROAD SUITE 800 EAST DALLAS, TEXAS 75244

March 11, 2024

Mr. Alessandro Tiani Head of Reserves Eni S.p.A. Via Emilia 1 20097 San Donato Milanese Italia

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the extent of the estimated net proved oil, condensate, liquefied petroleum gas (LPG), and gas reserves of certain properties in which Eni S.p.A. (Eni) has represented it holds an interest through its 63.04-percent corporate ownership of Vår Energi ASA. This evaluation was completed on March 11, 2024. The properties evaluated herein consist of fields located offshore Norway (Table 1). Eni has represented that these properties account for 6.6 percent on a net equivalent barrel basis of Eni's net proved reserves as of December 31, 2023. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Eni.

Reserves estimated herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Eni after deducting all interests held by others.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was provided by or on behalf of Eni. In the preparation of this report we have relied, without independent verification, upon information furnished by or on behalf of Eni with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

DEGOLYER AND MACNAUGHTON

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) 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.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

DEGOLYER AND MACNAUGHTON

Undeveloped oil and gas reserves – 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by or on behalf of Eni, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

The proved undeveloped reserves estimates were based on opportunities identified in the plans of development provided by or on behalf of Eni.

Eni has represented that it has confirmed through its corporate ownership that the operator is committed to the development plans provided by or on behalf of Eni and that the operator has the financial capability to execute the development plans, including the drilling and completion of wells and the installation of equipment and facilities.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP and OGIP.

When applicable, estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories.

When applicable, other engineering methods were used to estimate recovery factors based on analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in production-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined in the Definition of Reserves section of this report.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

DEGOLYER AND MACNAUGHTON

Data provided by or on behalf of Eni from wells drilled through December 31, 2023, and made available for this evaluation were used to prepare the reserves estimates herein. The reserves estimates were based on consideration of monthly production data available only through October 2023. Estimated cumulative production, as of December 31, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. LPG reserves estimated herein consist primarily of propane and butane fractions and are the result of low-temperature plant processing. Oil, condensate, and LPG reserves included in this report are expressed in millions of barrels (106 bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil, condensate, and LPG reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas and fuel gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Gas reserves estimated herein are reported as marketable gas reserves; therefore, fuel gas is included as reserves. Marketable gas reserves estimated herein include 88 billion cubic feet (10⁹ ft³ ) of fuel gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in 10⁹ ft³ .

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein consist of both associated and nonassociated gas.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by or on behalf of Eni in United States dollars (U.S.\$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Oil, Condensate, LPG, and Gas Prices

Prices were furnished for each field and were held constant for the remaining producing lives of the fields. The oil, condensate, LPG, and gas prices provided were represented to be based on a reference price, 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, unless prices are defined by contractual agreements. Price differentials to a Brent oil reference price of U.S.\$83.27 per barrel were provided for each field on behalf of Eni. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were U.S.\$83.53 per barrel of oil, U.S.\$73.14 per barrel of condensate, and U.S.\$50.30 per barrel of LPG. A Title Transfer Facility gas price index reference price of U.S.\$13.24 and differentials to that reference price were provided for each field on behalf of Eni. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was U.S.\$13.94 per thousand cubic feet of gas.

Operating Expenses, Capital Costs, and Abandonment Costs

Operating expenses and capital costs were estimated based on information provided by or on behalf of Eni and referenced to existing economic conditions. In certain cases, future expenditures, either higher or lower than existing expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by or on behalf of Eni and were not adjusted for inflation. The abandonment costs are inclusive of costs incurred for existing wells and facilities as well as those for future development associated with the proved reserves estimated herein. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

DEGOLYER AND MACNAUGHTON

Taxes and Royalty

The fields evaluated herein are subject to a Norway ordinary tax and a special petroleum tax that combine to a marginal tax rate of 78 percent. For corporate tax purposes, depreciation is based on the application of the straight-line method over 6 years. Tax reimbursement for the cost of field abandonment is considered during the year of abandonment and the following forecast year. There is no royalty for the fields evaluated herein.

In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, LPG, and marketable gas reserves of certain properties located offshore Norway in which Eni has represented it holds an interest through its 63.04-percent corporate ownership of Vår Energi ASA.

The estimated net proved reserves, as of December 31, 2023, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in millions of barrels (106 bbl) and billions of cubic feet (10⁹ ft³ ):

	Estimated by DeGolyer and
	MacNaughton
	Net Proved Reserves
	as of December 31, 2023
	Oil,
	Condensate,
	and LPG	Marketable Gas
	(106bbl).	(109ft3)
Total Proved	326	516

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2023, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716

Regnald A. Boles, P.E. Executive Vice President

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Regnald A. Boles, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

• 1. That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Eni dated March 11, 2024, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.
• 1. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1983; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, and the European Association of Geoscientist & Engineers; and that I have more than 40 years of experience in oil and gas reservoir studies and evaluations.

Regnald A. Boles, P.E. Executive Vice President

DeGolyer and MacNaughton

TABLE 1
---------	--	--

Country Field
Norway
Åsgard
Balder
Bauge
Bøyla
Breidablikk
Eldfisk
Embla
Fenja
Fram
Goliat
Grane
Gungne
Halten Øst
Heidrun Hyme
Johan Castberg
Kristin
Lavrans
Marulk
Mikkel
Morvin
Norne
Ormen Lange
Ringhorne Øst
Sigyn
Skuld
Sleipner Øst
Sleipner Vest
Snorre
Statfjord
Statfjord Nord
Statfjord Øst
Svalin
Sygna
Tommeliten Alpha
Tor
Tordis
Trestakk
Tyrihans
Urd
Verdande
Vigdis

Regulation

Criteria for the implementation of the clawback and malus principle provided for by Eni's Remuneration Policy

Regulation approved by Board of Directors of October 26, 2023

1. FOREWORD

1.1 This document¹ regulates the criteria for implementing the claw back and malus clauses (hereinafter "Clauses"), subject to the conditions listed below, applied to the monetary or stock incentive variable plans, both short and long term, disbursed and/or granted and/or allocated (hereinafter "Incentives") to the Directors with delegated powers, Managers with strategic responsibilities and other Managers in the Company (hereinafter "Eni Managerial Resources"), in accordance with the provisions of the Purposes and General Principles of Eni Remuneration Policy, and in line with the recommendations introduced by the Corporate Governance Code for listed companies to which the company adheres.

1.2 This Regulation was amended, with a board resolution of October 26, 2023 to comply with Section 954 of the Dodd-Frank Act² , with the related Securities and Exchange Commission ("SEC") implementing regulation³ and with the NYSE listing standards⁴ , as further detailed under article 4 below, applicable to the Company due to its listing in the United States, to regulate the recoupment of erroneously awarded Incentive-Based Compensation in the event of an accounting restatement, in accordance with the terms and conditions established by the aforementioned regulation.

1.3 The provisions contained in this Regulation shall apply to all Incentives granted after the date of approval by the Board of Directors; to this end, the regulation of the aforementioned Incentives expressly refers to this Regulation.

1.4 The possible activation of the Clauses, following the investigations carried out, is without prejudice to any further action to protect the Interests of the Company, based on the assessments of the specific circumstances of event.

2. DEFINITIONS

For the purposes of these Regulations, if the conditions described in the Article 3 below are met:

– the term "malus" refers to the Company's option to withhold/withdraw Incentives, already vested or in course of vesting but not yet paid and/or granted;

– the term "clawback" refers to the Company's option to request a refund of Incentives already paid and/or granted;

– the expression "Incentives-Based Compensation" refers to any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a financial reporting measure;

– the expression "Financial Reporting Measure" refers to: (i) measures of result or of financial condition that are determined on the basis of the accounting standards used in preparing the financial statements of the Company and any measure derived in whole or in part from these measures⁵ , (ii) the share price and (iii) the total shareholder return ("TSR")⁶ .

²Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

Page 1 of 5

¹ Approved by the Board of Directors on March 12, 2015, and subsequently amended on October 26, 2017 and October 28, 2020.

³ As amended, Regulation S-K, Part 229; Regulation S-T, Part 232; Securities Exchange Act of 1934, Parts 240 and 249, Form 20- F; Form 40-F; Form 10-K; Investment Company Act of 1940, Parts 270 and 274, Form N-CSR.

⁴ As used herein, it shall mean Section 303A.14 of the NYSE Listed Company Manual.

⁵Though not necessarily in theCompany's financialstatements or SEC filings. The definition includes measures of results or financial condition non-GAAP or "adjusted".

⁶ Indicator that measures the overall return of a share as the sum of the capital gain and reinvested dividend components.

This document is an English translation, for informative purposes only, of the Italian text of the official Regulation approved by Eni's Board of Directors ("Regolamento Criteri Attuativi delle clausole di clawback e malus previste dalla Politica sulla Remunerazione Eni") . For legal purposes, in case of any conflict or discrepancies between the two texts, the Italian one shall prevail.

3. REQUIREMENTS AND TERMS OF APPLICATION IN CASE OF RECOVERY OTHER THAN ACCOUNTING RESTATEMENT

3.1 The Company reserves the right to apply malus and/or claw back clauses to those Incentives based on data, relating to performances and/or to the results achieved, that were subsequently found to be manifestly misstated, as verified by the competent company control functions, within a maximum term of three years from the date they were disbursed, carrying on with the process to review the results and recalculate the incentives, after revising the data. The refund request shall be activated with reference to the actual results achieved, in accordance with the procedures allowed by the legislation in force, taking also into due consideration tax and social security contributions regulations. In the case of stock-based Incentives, the refund request will conventionally address the monetary value of the stock, calculated at the date of its final assignment to the Manager. For the purposes of this Regulation, any inaccuracies that have not affected the final calculation of the incentive amount are not deemed to be significant.

3.2 In case of:

a) fraudulent alteration of the data used to calculate the final results in relation to the assigned targets and in any case of the data on which the disbursement, granting or allocation of incentives is based, for the purposes of gaining the right to receive an incentive;

b) termination for disciplinary reasons, including serious and deliberate violations of the law and/or regulations, of the Code of Ethics or any other Company rules;

according to the seriousness of the conduct in question, the Company reserves the right to activate the malus and/or clawback clauses, within a maximum period of five years from the payment of the incentive or the definitive assignment of the stocks.

In such cases Eni shall activate the Clauses (in accordance with the procedures allowed by the legislation currently in force and also taking into consideration tax and social security contributions regulations) with respect to all Incentives granted or to be granted, assigned or to be assigned or awarded or to be awarded, relating to the year (or years) to which the existence of the aforementioned conditions has been ascertained, as well as to any Incentive in course of vesting at the date of the assessment.

3.3 The Clauses may be exercised upon conclusion of the audit activities conducted by the relevant Company control functions within the time limits indicated above. Upon expiry of these limits, the incentives paid out or granted or the right to be paid or to be granted the allocated incentives based on the achieved and finalized results shall be considered acquired and finally gained.

In case audit activities begun within the four months preceding the expiry of the aforementioned time limits, these same limits may be extended by the relevant Company departments for a maximum of 120 days, if there is an objective need to complete the audit activities.

3.4 In case it is necessary to start legal proceedings to verify the circumstances referred to in Articles 3.1 and/or 3.2, Clauses activation and relevant terms, as well as any Incentive obligation, will be suspended, until the final outcome of the legal proceedings, with which Eni must promptly comply. Pending the legal proceedings, Eni reserves the right to disburse and/or grant the vested incentives if, upon conclusion of the internal audits referred to in Article 4.2, the competent body, indicated under Article 4.3, establishes that the allegations of misconduct referred to in Articles 3.1 and/or 3.2, which may be the subject of the legal proceedings in question, have no basis. This does not affect Eni's right to subsequently request the return of the incentives paid out if the judicial findings confirm the existence of the conduct in question. For the purposes of the aforementioned suspension of terms and of Incentive obligations, the actions and/or phases relating to the preliminary investigations by the judicial authorities, or the issue of any warrants in relation to the persons being investigated, are not deemed relevant.

3.5 If the employment contract of a manager that is subject to a clawback request is terminated for any reason, Eni may offset any amount due for any reason to the manager against the incentives subject to clawback.

Page 2 of 5

This document is an English translation, for informative purposes only, of the Italian text of the official Regulation approved by Eni's Board of Directors ("Regolamento Criteri Attuativi delle clausole di clawback e malus previste dalla Politica sulla Remunerazione Eni") . For legal purposes, in case of any conflict or discrepancies between the two texts, the Italian one shall prevail.

4. REQUIREMENTS AND TERMS OF APPLICATION IN CASE OF RECOVERY FROM ACCOUNTING RESTATEMENT

4.1 In the event that the Company is required to prepare an accounting restatement due to the material noncompliance of the Company with any financial reporting requirements under applicable securities laws⁷ , including any required accounting restatement to correct an error in previously issued financial statements and which would result in a material error if the error were corrected only in the current period or left uncorrected in the current period⁸ , the Company shall recover reasonably promptly the amount of erroneously awarded Incentive-Based Compensation.

The amount of compensation subject to recovery is calculated to the extent that exceeds the amount that would have been determined on the restated data, computed without regard to any taxes paid, in the three fiscal years preceding the date of the adjustment ("recovery period"), meaning the earlier of:

– the date on which the Board of Directors, or other delegated body, concludes, or reasonably ought to have concluded, that the Company is required to prepare an accounting adjustment.

– the date on which a court, regulator or other legally authorized body directs the Company to prepare an accounting adjustment.

For purposes of this article 4, Incentive-Based Compensation shall be deemed "received" in the Company's fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period.

4.2 The recovery described in the above art.4.1 applies⁹ to executive officers, as defined by SEC regulations, and to all other managerial resources, in office during the vesting period of the aforementioned Incentives and on condition that the Company has a class of securities listed on the NYSE.

4.3 For Incentive-Based Compensation based on the price of the Company's common shares or TSR, where the amounts erroneously awarded do not derive directly from the mathematical application of the accounting restatement, the amounts to be recovered shall be determined on the basis of the reasonable estimate of the effect of the adjustment on the share price or TSR. In such cases, the Company will maintain documentation of its determination of such reasonable estimate and provide such documentation to the NYSE.

4.4 The Company will recover the variable incentive based on financial parameters erroneously determined in the cases envisaged by this article and in compliance with the provisions of article 5.3, letter a ), b ), c ) below, except in cases where the direct expenses paid to third parties to trigger the recovery clauses would exceed the amounts to be recovered, subject to a reasonable recovery attempt, to be documented to the NYSE.

4.5 The Company will not indemnify, directly or indirectly (for example through the payment or reimbursement of premiums for third party insurance policies to finance potential recovery obligations), any of the subjects referred to in the previous article 4.2, for the losses deriving from the recovery of erroneously determined incentive based on financial measures.

4.6 These provisions and the information on the recovery actions activated, in accordance with the requirements of U.S. Federal securities laws, will be subject to disclosure and communication required to be included in the required SEC filings.

Page 3 of 5

⁷ Case of "big R": the financial statement is withdrawn, and the company is required to prepare an adjusted one due to material misstatement.

⁸ Case of "little R: the previous financial statements are not reissued but are subject to restatement in the financial statements during which the administrative body evaluates the materiality of the restatement compared to the current financial statements and proceeds to restate the financial statements of the comparative periods.

⁹ In relation to the variable incentive paid after October 2, 2023 (date of entry into force of the standard listings).

This document is an English translation, for informative purposes only, of the Italian text of the official Regulation approved by Eni's Board of Directors ("Regolamento Criteri Attuativi delle clausole di clawback e malus previste dalla Politica sulla Remunerazione Eni") . For legal purposes, in case of any conflict or discrepancies between the two texts, the Italian one shall prevail.

5. ROLES AND RESPONSIBILITIES

5.1 The relevant Company departments of HC&P ensure the widest possible dissemination and knowledge of the principles contained in this Regulation in order to promote proper participation in the Company's incentive schemes, while at the same time discouraging the adoption of behaviours that, although aimed at achieving the objectives set, could potentially end up damaging the assets and reputation of the Company. The relevant Company departments of HC&P also ensure that the activation, allocation and liquidation of the short and long-term incentive plans are subject to prior verification of the absence of any preliminary investigations and/or disciplinary actions pending against the beneficiary due to conduct relating to the breaches referred to in Article 3.

5.2 In accordance with the provisions of the Internal Control and Risk Management System, the Company's control functions, in performing their duties or as specifically directed by CFO or HC&P functions, and with the support of the Internal Audit Department if necessary, carry out preliminary investigations to ascertain facts potentially relevant to the cases mentioned in Articles 3 and 4, and promptly transmit the documentation concerning the proved verification to the competent body or company function for the possible activation of the Clauses.

5.3 Following the results of the above mentioned investigations, any clawback action is established:

• a) by the Board of Directors, on the proposal of the Remuneration Committee, with regard to Directors with delegated powers (having also consulted the Board of Statutory Auditors), as well as to Managers with strategic responsibilities appointed by the Board on the basis of the Company by-laws and governance model currently in force;
• b) by the Board of Directors, on the proposal of the Chairman in agreement with the Chief Executive Officer and General Manager, subject to the favourable opinion of the Control and Risk Committee and having consulted the Board of Statutory Auditors, with regard to the Internal Audit Manager;
• c) by the Chief Executive Officer and General Manager, with regard to Directors with strategic responsibilities that are not included in the provisions above;
• d) by the relevant human resources function with regard to the other Eni managerial resources.

5.4 In performing the assessments under their responsibility and to support the relevant deliberations, the Board of Directors may make use of the advisory and preparatory support of the Board's Committees as well as (also for persons other than Directors with executive powers) the opinion of the Board of Statutory Auditors.

5.5 The Chief Executive Officer and the General Manager promptly inform the Board of any authorized clawback measures (in accordance with Article 5.3 c), specifying the reasons they are based on and confirming that they are in line with the principles established in this Regulation.

Page 4 of 5

This document is an English translation, for informative purposes only, of the Italian text of the official Regulation approved by Eni's Board of Directors ("Regolamento Criteri Attuativi delle clausole di clawback e malus previste dalla Politica sulla Remunerazione Eni") . For legal purposes, in case of any conflict or discrepancies between the two texts, the Italian one shall prevail.

6. IMPLEMENTATION AND UPDATING OF THIS REGULATION

6.1 The Compliance Committee and/or the relevant Company departments ensure any updates to present Regulation that may be required by the internal regulations and procedures, within 6 months of its approval, in order to guarantee its consistent and effective application in relation to the managerial resources of Eni and its subsidiaries while respecting the managerial autonomy of the listed subsidiaries as well as the applicable legislation for companies subject to prudential supervision and the local legislation applicable to foreign companies.

6.2 The HC&P, with the support of the relevant Compensation & Benefits department, ensures the implementation of the conditions and/or regulations of the Incentive Plans, in compliance with the principles outlined in this Regulation, ensuring also the effectiveness of the Contract with regard to the respective beneficiaries.

6.3 The HC&P, with the support of the relevant Compensation & Benefits department, also monitors the development of legislation and best practice at both national and international levels in order to support the Remuneration Committee when drafting proposals to update the clawback and malus principles contained in the Eni Remuneration Policy and in this Regulation.

7. REPORTING

7.1 If Clauses pursuant to art. 5.2 above are activated, the HC&P , with the support of the relevant Company departments, collects and storages the information on the implementation of this Regulation, specifying: a name list of clawback/malus cases started, their stage of completion, mentioning for each one the relevant information, in particular with regard to the violations identified, the incentives and the amounts recovered, and any legal proceedings begun in order to recovery the incentives.

7.2 The HC&P, based on this information, prepares a report to be forwarded to the Chairman and to the Chief Executive Officer and General Manager, to the Board of Statutory Auditors, to the Remuneration Committee and to the Control and Risk Committee. The report will also indicate if this Regulation consequently requires updating.

7.3 The Company will file these Rules with the SEC and their contents will be disclosed, as appropriate, in accordance with the US federal securities laws.

Page 5 of 5

This document is an English translation, for informative purposes only, of the Italian text of the official Regulation approved by Eni's Board of Directors ("Regolamento Criteri Attuativi delle clausole di clawback e malus previste dalla Politica sulla Remunerazione Eni") . For legal purposes, in case of any conflict or discrepancies between the two texts, the Italian one shall prevail.

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.

EU Taxonomy

Regulation EU 852/2020 of the European Parliament and of the Council enacted in June 2020 has established a classification system of economic activities based on criteria of environmental sustainability for the purposes of channeling productive investments.

Based on the Regulation, an economic activity qualifies as environmentally sustainable where that economic activity:

i) contributes substantially to one or more of the environmental objectives of the EU (set out in Article 9 of the Regulation);

ii) does not significantly harm any of the environmental objectives;

iii) is carried out in compliance with the minimum safeguards (as referred to the art. 18 of the regulation) foreseen by the Regulation, which are procedures implemented by an undertaking that is carrying out an economic activity to ensure a responsible business conduct;

iv) complies with technical screening criteria that have been established by the European Commission, which define the performance thresholds whereby an economic activity offers a substantial contribution to an environmental objective and at the same time does not harm in a significant way any of the other objectives.

The Taxonomy Regulation has established six environmental objectives:

• a) climate change mitigation;
• b) climate change adaptation;
• c) the sustainable use and protection of water and marine resources;
• d) the transition to a circular economy;
• e) pollution prevention and control;
• f) the protection and restoration of biodiversity and ecosystems.

IDENTIFICATION OF ENI'S ELIGIBLE AND TAXONOMY-ALIGNED ACTIVITIES

Based on the powers conferred by the Taxonomy, the Commission has issued for each of the Taxonomy objectives a delegated act which states the economic activities eligible to make a substantial contribution to an objective. Technical screening criteria ("TSC") are established for each economic activity, which are the performance conditions that the operator of an economic activity must assess to verify the substantial contribution to an objective and respect of the "do no significant harm" principle.

In the initial stage of the Taxonomy roll-out, which was applied to financial reports for 2021 and 2022, the Commission has regulated just the economic activities eligible to make a substantial contribution to the climate objectives: climate change mitigation and climate change adaptation by means of Delegated Regulation (EU) 2021/2139 (the "Climate Delegated Act") as complemented by the nuclear and gas-related activities listed in Delegated Regulation (EU) 2022/1214 (the "Complementary Climate Delegated Act").

In 2023, the Commission has issued the Environmental Delegated Regulation (EU) 2023/2486 whereby it has defined the economic activities eligible to make a substantial contribution to the four environmental objectives, and the relevant TSC. Furthermore, the Climate Delegated Act has been updated by modifying the TSC applied to certain economic activities and by introducing new economic activities eligible to substantially contribute to the climate objectives (e.g. construction of aircrafts and airline passenger transport).

An activity is "taxonomy-eligible" if it is described in a delegated act adopted under the Taxonomy Regulation, irrespective of whether it complies with the technical screening criteria. Such an activity could potentially make a substantial contribution to a given environmental objective.

The Delegated Regulation on the reporting obligations in connection with the Taxonomy (see below) has been amended by providing that nonfinancial undertakings will only report the share of eligible revenues, capital expenditures and operating expenditures associated with the eligible activities defined in the Environmental Delegated Act, pairing the same reporting approach utilized with the climate objectives, consisting of not applying the TSC for the first reporting year (this also applies to the new activities of the Climate Delegated Act).

An activity is "taxonomy-aligned" if it contributes substantially to one or more environmental objectives, does no significant harm "DNSH" to any of the other objectives, is carried out in compliance with minimum human and labor rights safeguards, and complies with the relevant technical screening criteria.

Eni has assessed the economic activities performed by the Group against the economic activities qualifying for the taxonomy's climate mitigation and climate adaptation objectives, which have been identified by Delegated Regulation EU 2021/2139 (the "Climate Delegated Act") and the nuclear and gas-related activities listed in Delegated Regulation EU 2022/1214 (the "Complementary Climate Delegated Act").

This assessment has comprised a two-step process: first, the Group economic activities have been screened to score those eligible in accordance with the above-mentioned delegated acts.

Then, the technical screening criteria have been applied to verify alignment of each of the Group's eligible economic activities with the relevant TSC to verify the substantial contribution criteria and respect of the DNSH criteria. The assessment of compliance with the minimum safeguards provided by art. 3 "c" of the Regulation has been performed at Group level.

No significant changes to Eni's existing reporting boundaries have been made in connection with the eligible economic activities identified pursuant to the Environmental Delegated Act, considering the Taxonomy constrain about the non-eligibility of activities that could lead to a lock-in of assets that undermine long-term environmental goals (for example the production of alternative water resources for purposes other than human consumption), while some activities are expected to become relevant when they commence to earn revenues from third parties (for example the activity of remediation of contaminated sites and areas).

REPORTING OBLIGATIONS AND BASIS OF PRESENTATION

Based on article 8 of the Taxonomy Regulation, non-financial undertakings which are subject to the obligation to publish a consolidated nonfinancial statement pursuant to Article 19a or Article 29a of Directive 2013/34/EU of the European Parliament and of the Council are required to comply with a transparency regime by disclosing in their non-financial disclosures three key performance indicators (KPI) relating to the proportion of their turnover derived from products or services associated with economic activities that qualify as environmentally sustainable and the proportion of their capital expenditure and the proportion of their operating expenditure related to assets or processes associated with economic activities that qualify as environmentally sustainable as per the Regulation. The Commission has adopted a delegated regulation (2178/2021) specifying the content of KPIs and presentation of information concerning environmentally sustainable economic activities and the reporting methodology.

Disclosures presented herein by Eni are intended to comply with that regulation.

EU Taxonomy Disclosures as per Annex I to COMMISSION DELEGATED REGULATION

(EU) 2021/2178 KPIs of non-financial undertakings

EUROPEAN TAXONOMY: SUMMARY TEMPLATE OF ENI GROUP KPI

ENI GROUP - YEAR 2023	TURNOVER		CAPEX		OPEX
	Absolute amount in € mln	proportion %	Absolute amount in € mln	proportion %	Absolute amount in € mln	proportion %
A. TAXONOMY-ELIGIBLE ACTIVITIES
A.1. ENVIRONMENTALLY SUSTAINABLE
ACTIVITIES (TAXONOMY-ALIGNED)	1,119	1.2%	2,012	14.7%	190	4.8%
A.2. TAXONOMY-ELIGIBLE BUT NOT ENVIRONMENTALLY SUSTAINABLE ACTIVITIES
(NOT TAXONOMY-ALIGNED ACTIVITIES)	5,147	5.5%	371	2.7%	368	9.2%
TOTAL A.1 + A.2	6,266	6.7%	2,383	17.4%	558	14.0%
B. TAXONOMY-NON-ELIGIBLE ACTIVITIES	87,451	93.3%	11,282	82.6%	3,421	86.0%
TOTAL A+B	93,717	100.0%	13,665	100.0%	3,979	100.0%

SUMMARY TABLE OF TAXONOMY KPI 2023 - 2022

	Turnover		Capex		Opex
(€ mln)	2023	2022	2023	2022	2023	2022
Electricity generation using solar photovoltaic technology	192	31	606	603	86	15
Electricity generation (wind)	168	79	138	906	25	28
Manufacture of biogas and biofuels for use in transport and of bioliquids	660	667	224	97	64	24
Manufacture of plastics in primary form	59		745		5
Electricity generation from bioenergy	35	41	2	1	8	5
Underground permanent geological storage of CO2			145	78
Infrastructure enabling low carbon road transport and public transport			121	60
Other	5	5	31	8	2	3
Total aligned	1,119	823	2,012	1,753	190	75
Consolidated	93,717	132,512	13,665	12,396	3,979	4,160
Taxonomy KPI	1.2%	0.6%	14.7%	14.1%	4.8%	1.8%

1. Content of KPIs

1.1. Specification of key performance indicators (KPIs)

1.1.1. KPI related to turnover (turnover KPI)

Eni Group's consolidated financial statements are prepared in accordance with the International Financial Reporting Standards "IFRS" as adopted by Commission Regulation (EC) 1126/2008.

In compliance with that, the Group turnover and the turnover relating to Taxonomy-aligned economic activities and to Taxonomy-eligible economic activities (not Taxonomy-Aligned activities) have been recognized pursuant to International Accounting Standard (IAS) 1, paragraph 82 a).

The 6.7% share of eligible and aligned turnover is calculated as the part of turnover derived from eligible or aligned economic activities (numerator) divided by total turnover (denominator).

Eligible and aligned economic activities are described under paragraph 1.2.2. The denominator comprises the Sales from operations (Revenues) line from the Consolidated Statement of Income. A reconciliation is provided below:

TURNOVER

Turnover	Aligned	Eligible	Total
(mln €)	activities	activities	Group
Revenues from contracts with customers	1,119	5,147	93,717

The proportion of turnover referred to in Article 8(2), point (a), of Regulation (EU) 2020/852 "turnover KPI" is calculated as the part of the turnover derived from products or services associated with Taxonomy-aligned economic activities (numerator), divided by the Group total turnover (denominator).

The Group turnover and the turnover of eligible and aligned economic activities are recognized net of the effects of commodity derivatives activated to manage the Group's exposure to movements in the prices of energy commodities, which qualify and are designated as cash flow hedges due to the efficacy of the relationship between the instrument and the hedged item, whereby a cash flow is either paid or received at the delivery of the underlying commodity. The mark-to-market of cash flow hedges relating to a forecast transaction are taken to other comprehensive income.

Other commodity derivatives utilized by the Group to manage exposure to the commodity risks, which lack the requirements to be recognized in accordance with the own use exemption or to be qualified as hedges in accordance with IFRS, are marked to market with gains or losses recognized through profit and loss in a separate line item from revenues. Such line item comprises the ineffective portion of cash flow hedges.

1.1.2. KPI related to capital expenditure (CapEx) (CapEx KPI)

Capital expenditure "CapEx" of the Eni Group and the "CapEx" relating to eligible economic activities and to aligned economic activities cover costs that are accounted based on:

(a) IAS 16 Property, Plant and Equipment, paragraphs 73, e), point i) and point iii);

(b) IAS 38 Intangible Assets, paragraph 118, e), point i);

(c ) IFRS 16 Leases, paragraph 53, point h).

CapEx also covers additions to tangible and intangible assets resulting from business combinations.

The Group does not engage in economic activities that are recognized in accordance with IAS 40 and IAS 41.

The 17.4% share of CapEx of eligible and aligned economic activities is calculated as the part of CapEx derived from eligible or aligned economic activities (numerator) divided by total Group CapEx (denominator). Eligible and aligned economic activities are described under paragraph 1.2.2. The denominator comprises additions recognized in the financial year to the following line items of the Group's assets reported in the Group statement of financial positions at December 31, 2023: "Property, plant and equipment", "Intangible assets" and "Right of Use" as disclosed under footnotes no. 12, 13 and 14 to the Group consolidated financial statements, as well as the portion of purchase price allocated to PP&E and intangible assets with definite useful lives as part of the business combinations closed in the financial year.

Costs incurred to purchase plant and equipment from suppliers whose payment terms matched classification as financing payables, have been recognized among additions to PP&E and are included in the denominator and, when applicable, in the numerator of the CapEx KPI.

A reconciliation is provided below:

CAPEX

Capex	Aligned	Eligible	Total
(mln €)	activities	activities	Group
Additions to tangibles and intangibles assets	754	330	9,215
Goodwill purchased			25
Additions to rights to use leased assets	16	10	1,584
Acquisitions/Change in the scope of consolidation	1,157	31	1,842
Other investment	85		1,024
Less
Goodwill purchased			(25)
Total Capex	2,012	371	13,665

The proportion of CapEx referred to in Article 8(2), point (b), of Regulation (EU) 2020/852 "CapEx KPI" is calculated as the part of CapEx relating to aligned economic activities (numerator) divided by the Group total CapEx (denominator) as specified in points 1.1.2.1. and 1.1.2.2. of Annex I to Commission Delegated Regulation (Eu) 2021/2178.

1.1.3. KPI related to operating expenditure (OpEx) (OpEx KPI)

The 14.0% share of eligible and aligned operating expenditure "OpEx" is calculated as the part of OpEx relating to eligible or aligned economic activities (numerator) divided by the Group total Opex (denominator). Eligible and aligned economic activities are described under paragraph 1.2.2. A reconciliation is provided below:

OPEX

Opex (mln €)	Aligned activities	Eligible activities	Total Group
Costs of R&D expensed through profit and loss	4	39	166
Operating expenses	186	329	3,813
Total Opex	190	368	3,979

The proportion of OpEx referred to in Article 8(2), point (b), of Regulation (EU) 2020/852 "OpEx KPI" is calculated as the Opex of aligned economic activities (numerator) divided by the Group total OpEX denominator as specified in points 1.1.3.1. and 1.1.3.2. of Annex I to Commission Delegated Regulation (Eu) 2021/2178.

1.2. Specification of disclosures accompanying the KPIs of non-financial undertakings

1.2.1. Accounting policy

Economic and financial data relating to Eni's eligible and aligned economic activities for calculating the Taxonomy's KPIs and proportion of eligible turnover, capex and opex, have been extracted from the Group accounting systems, the general ledger and the management accounting systems, which are used to prepare the separate financial statements of each consolidated subsidiary undertakings, mostly of which are in accordance with IFRS. Data extracted from separate financial statements are adjusted to align with the IFRS utilized in the preparation of the Group consolidated financial statements and for the consolidation transactions (intercompany sales and purchases, elimination of unrealized profit, etc.) to calculate Eni's Taxonomy KPIs and the eligible turnover, capex and opex proportion.

Therefore, data of turnover, OpEx and CapEx relating to Eni Group's aligned and eligible economic activities utilized in calculating the Taxonomy KPIs and the proportion of eligible activities are the same the Group used in preparing the consolidated financial statements.

In the case of mono-business consolidated subsidiary undertakings performing a given eligible activity, relevant economic and financial data for the calculation of the Group eligible proportions have been extracted from the general ledger and the financial accounting to retrieve amounts of revenues, operating expenditures, additions to property, plant and equipment (PP&E) and intangible assets, additions to the rightof-use and additions to PP&E and intangibles resulting from business combinations. In case of multi-business subsidiary undertakings, relevant data for calculating the Group eligible proportions have been derived also from the systems of managerial accounting that splits the accounts of the financial system and allocates revenues and cost amounts to different reporting objects: profit centers which correspond to business units, product lines which can share common costs, plants, capital projects, cost centers, etcetera, to support management's understanding of the drivers of the financial performance and cost control.

Such structure of accounting flows, which is employed in preparing the Group consolidated financial statements, ensure that turnover, OpEx and CapEx are recognized by the economic activity where the underlying transactions occur, by this way avoiding double counting. This is explained by evidence that amounts recognized or allocated by the managerial accounting system are reconciled with the accounting system and the general ledger. Common costs are apportioned to different reporting objectives and economic activities based on disaggregation criteria that reflect how common inputs are absorbed.

Operating costs of Eni Group companies to define the proportion of the opex of aligned and eligible activities to the Group total were determined on the basis of the managerial accounting system and Eni's control model of fixed costs which, starting from accounting data relating to purchases of goods and materials, services, labour costs and other charges, excludes raw materials costs, industrial plant variable costs and costs of products for resale and aggregates the remaining cost items in relation to the different measurement and control stages in the manufacturing/sale process:

• fixed industrial costs which include the labor costs for personnel involved in the maintenance, operation and servicing of industrial plants, third-party services (mainly maintenance contracted to third parties), general plant costs, consumables (spare parts) and include energy efficiency actions at buildings and other properties, as well as the purchase of outputs from aligned activities to achieve CO2 emission reductions;

• non-capitalised research & development costs;

• commercial & marketing fixed costs;

• general and administrative costs.

For the purposes of reporting obligations, management has identified industrial fixed costs and non-capitalised R&D costs as the aggregate "opex" operating expenses corresponding to the definition of the denominator adopted by the Delegated Regulation on reporting.

In line with the provisions, the opex incurred to purchase enabling products or in relation to enabling manufacturing processes have been claimed by the economic activities carried out by Eni in compliance with Art. 16 of the Taxonomy Regulation so that do not lead to a lock-in of assets that undermine long-term environmental goals, considering their economic lives. In this context, the opex incurred by the E&P sector to increase energy efficiency/reduce CO2 emissions at oil & gas plants were excluded. This principle has also been applied to capex.

1.2.2. Assessment of compliance with Regulation (EU) 2020/852

1.2.2.1. Information on assessment of compliance with Regulation (EU) 2020/852

Eni's eligible activities for purpose of assessing their substantial contribution to the objective of climate change mitigation are:

3.14 manufacture of organic basic chemicals: production of monomers and other basic chemicals;

3.17 manufacture of plastics in primary form: production of polyethylene and styrene's obtained by processing monomers and production of resins and plastics from renewable feedstock;

4.1 electricity generation using solar photovoltaic technology: photovoltaic installations are managed by the Group subsidiary Plenitude and are located mainly in Italy, Spain, USA, Australia, Kazakhstan and France;

4.3 electricity generation from wind power: the production is obtained from onshore windmills that are managed by the Group subsidiary Plenitude and are located mainly in Italy, Spain, Kazakhstan;

4.4 electricity generation from ocean energy technologies: it is an inertial sea wave energy converter to convert the wave energy into electrical energy. This activity is in an experimental phase;

4.8 electricity generation from bioenergy: production of electricity in installations with a total rated thermal input below 2 MW and using gaseous biomass fuels;

4.10 Development of energy storage facilities in Italy and the United States;

4.13 manufacture of biogas and biofuels for use in transport and of bioliquids: production of biofuels by means of hydrogenating biofeedstock or waste organic materials. The manufactured product is a hydrogenated vegetable oil (HVO) that can be used as pure fuel or blended with fossil fuels to obtain a reduction in emitted CO2 from combustion. This activity is performed at the biorefinery of Gela (Sicily) and Venice with total production capacity of 1.1 mln tons/y;

4.20 cogeneration of heat/cool and power from bioenergy: production of steam and electricity by means of

cogeneration, utilizing forestry biomass at the Crescentino plant (Italy);

5.3-5.4 construction, extension and operation of wastewater collection, treatment and supply systems and renewal of wastewater collection, treatment and supply system;

5.7/5.8 anaerobic digestion of bio-waste: anaerobic digestion, biogas production and subsequent cogeneration for electricity production, as well as compost, at the Po' Energia Srl plant from organic fraction coming from the separate collection of municipal waste, as well as production of compost;

5.12 underground permanent geological storage of CO2: this activity leverages depleted reservoirs operated by Eni. The main ongoing projects are the Hyte hub in UK to upgrade Eni's depleted reservoirs in the Liverpool bay to permanently store CO2 emitted by local businesses in hardto-abate industries and the Ravenna hub, off Italy;

6.5 transport by motorbikes, cars and light commercial vehicles: Enjoy rental service based on the "free floating" model with collection and release of the vehicle at any point within the area covered by the service. The fleet consists of internal combustion, hybrid and electric vehicles;

6.15 infrastructure enabling low carbon road transport and public transport: this activity comprises construction, maintenance, and operations of electric charging points for EV, and is performed by Eni's subsidiary Plenitude.

The above-mentioned activities are also eligible for the objective of climate change adaptation. However, the Group does not engage in economic activities that manufacture productions and solutions for climate change adaptation. Therefore, the objective of climate change adaptation has been assessed as far as necessary to verify that each of Eni's eligible economic activities does not significantly harm any of the objectives of the Taxonomy, in compliance with art. 3 of regulation (UE) 2020/852.

Regarding the environmental objectives regulated in 2023, Eni has identified as eligible activities for purpose of assessing in the next year their substantial contribution to the objective of the circular economy: (i) 1.1 manufacturing of plastic packaging; (ii) 2.5 recovery of organic waste through anaerobic digestion or composting. Both activities were assessed in 2023 for the purpose of a substantial contribution to the objective of climate change mitigation (reference activities 3.17 and 5.7/5.8).

The Company has excluded from its eligible activities the following activities:

3.10 manufacture of hydrogen;

6.10 sea and coastal freight water transport, vessels for port operations and auxiliary activities, which support

hydrocarbons;

The reason is their non-compliance with the lock-in clause stated at art. 16 of the Taxonomy.

Eni has assessed whether its eligible economic activities are environmentally sustainable in compliance with the provisions of art. 3 of regulation (UE) 2020/852 complemented by Commission delegated regulation (UE) 2021/2139 adopted pursuant to articles 10-11 par. 3 of the above mentioned regulation, which establishes the technical screening criteria which set the performance conditions whereby an economic activity can be claimed to contribute substantially to the objective of climate change mitigation, does not significantly harm any of the environmental objectives of the Taxonomy and is carried out in compliance with the minimum safeguards laid down in Article 18 of regulation (UE) 2020/852. Based on those evaluations, the Group concluded that the following activities are environmentally sustainable as per regulation (UE) 2020/852.

3.17. Manufacture of plastics in primary form

The economic activity includes: i) production of resins, especially biodegradable and compostable polyesters and copolyesters, derived in whole or in part from renewable raw materials; ii) production of biodegradable and compostable plastics, i.e., blends of resins derived in whole or in part from renewable raw materials. These production lines belong to Novamont, whose control was acquired in the fourth quarter of 2023.

The economic activity "Manufacture of plastics in primary form " is a transitional activity as of Article 10, paragraph 2, of Regulation (EU) 2020/852 if it meets the technical screening criteria described at the point 3.17 of Regulation (EU) 2021/2139.

Substantial contribution to climate change mitigation

For the assessment of substantial contribution to climate change mitigation, criterion c) related to activity 3.17 as stated in EU Regulation 2021/2139 was applied, as follows:

c) derived in whole or in part from renewable raw materials, and the greenhouse gas emissions over their life cycle are lower than the greenhouse gas emissions in the life cycle of equivalent primary form plastics manufactured from fossil fuels. Greenhouse gas emissions over the life cycle are calculated using Recommendation 2013/179/EU or, alternatively, ISO 14067:2018 or ISO 14064-1:2018. Greenhouse gas emissions quantified over the life cycle are verified by an independent third party. Agricultural biomass used for manufacturing of plastics in primary form meets the criteria of Article 29, paragraphs 2 to 5, of Directive (EU) 2018/2001. Forest biomass used for manufacturing of plastics in primary form meets the criteria of Article 29, paragraphs 6 to 7, of the same directive.

In this context, chemicals derived from hydrocarbons were identified as equivalent to resins and plastics derived in whole or in part from renewable raw materials. These equivalent chemicals were identified considering chemical equivalence in terms of composition and equivalence in the chemical family.. For both product lines, the hydrocarbon-derived equivalent is PBAT. Subsequently, emissions from Novamont's activity and the hydrocarbon equivalent were calculated based on the Life Cycle Thinking methodology, which includes all stages of their respective supply chains (procurement, processing, transportation, and disposal). This analysis confirmed compliance with the stated criterion "c" of the Taxonomy.

Do No Significant Harm ("DNSH")

Climate change adaptation

The Group has conducted a risk assessment of the exposure of Novamont's production plants to acute and chronic weather events as anticipated by Appendix "A" to the Climate Delegated Regulation.

The main physical risk is of hydrogeological nature. The plants are located in a basin regulated by a hydrogeological plan coordinated by a basin authority. The plan identifies various risk scenarios related to landslides and floods and outlines the prevention measures and safety protocols adopted by the activity to mitigate potential damage due to adverse weather events. This plan and its mitigation measures are regularly updated based on the evolving physical risk situation. The activity has also adopted emergency plans that include procedures and safety protocols in the case of adverse events.

Transition to a circular economy

Not applicable

Pollution prevention and control

The activity meets the criteria of Appendix C of EU Delegated Regulation 2021/2139 as amended in 2023.

Sustainable use and protection of water and marine resources

Protection and restoration of biodiversity and ecosystems

The plants for the production of resins and plastics derived from renewable raw materials have obtained an Environmental Impact Assessment (VIA) under Directive 2011/92/EU and therefore adhere to the principle of not causing significant harm to the goal of sustainable water use and the protection and restoration of biodiversity and ecosystems.

4.1. Electricity generation using solar photovoltaic technology

Substantial contribution to climate change mitigation

The activity generates electricity using solar PV technology.

Do no significant harm ("DNSH")

Climate change adaptation

The management has assessed the risk of exposure of the Group's assets to climate-related acute and chronic hazards, following the guidelines of Appendix A to the Climate Delegated Regulation, setting generic criteria for DNSH to climate change adaptation.

The Group has put in place management control systems and procedures to identify, evaluate and mitigate physical climate risks, which the Company defines as the risk that potential perspective changes in meteorological patterns, extreme weather phenomena and gradual changes in weather conditions and in the physical environment linked to climate change may adversely and significantly affect assets' future performance, safety of operations and future expected cash flows, so to significantly harm the objective of climate change adaptation.

The management regularly reviews the exposure of the Group's assets to the acute and chronic climate-related hazards described in the abovementioned Appendix A and other natural hazards based on a proprietary methodology to identify physical climate risks over a long-term horizon. The purpose of this risk assessment is to define and execute mitigation plans designated to adapt the Group assets to current or expected risks, considering the already existing barriers at each Company's asset. This assessment considers various timing horizons based on assets' useful lives (about thirty years for solar installation, wind mills and biorefineries, whereas recharging points for EV have seven years of useful live).

Eni's assessment methodology of assets' exposure to natural hazards features the following steps:

• it utilizes input data furnished by an external provider, leader in the sector, which has elaborated detailed geographic maps of prospective climate-related risks ensuring a full coverage of onshore and offshore areas where Eni's assets are located. The sources of such climate maps combine the most updated climate forecast models, also incorporating historical weather patterns, to provide expected quantitative trends in the evolution of climate-related events ( with reference to quantitative parameters expected number of days with temperatures above or below historical averages, wind strength, rain intensity, eccetera);

• it develops a stress test of the current asset portfolio, without limiting to assets' residual useful lives, to evaluate the potential, perspective exposure to climate-related risks till 2050;

• it is performed yearly, and it will undergo continuous improvement based on the experience that will be accumulated over time, as well as the evolution in the framework on how to identify and measure climate-related risks;

• it utilizes the IPCC SSP5 - 8.5 scenario to project the expected future geographical maps of climate-related hazards;

• it utilizes the geographic coordinates of each Company's asset (longitude and latitude) to locate it in a given quadrant (each with an area of one square kilometer) as defined by the external provider to recognize the climate-related risks, which each asset is potentially exposed to over a thirty-year horizon based on the adopted climate scenario;

• it considers in the risk-evaluating process also third-party assets and assets of the supply chain, where relevant to a full understanding of the risks which each Eni's asset is exposed to.

Once climate-related hazards have been identified and classified, the management evaluates each asset's existing barriers or factors both physical ones (structural characteristics of an asset design, materials used in its construction, distance from the sources of possible hazards, containment walls, etc.) and systems and procedures (early warning systems, procedures to put in safety plants and equipment, existence of monitoring and verification plans, etc.).

The outcome of that review informs the management of the residual riskand:

• in case of chronic climate-related hazards, monitoring activities are designed, planned, and carried out leading to the possible implementation and follow-up of remediation measures;

• in case of acute climate-related hazards, the Asset Integrity Process is activated which can lead to the definition and activation of an adaptation plan is assessed.

Based on the assessment of this activity's exposure to climate-related hazards following the methodology and procedures described herein, the management has concluded that the Company's PV facilities are not exposed to any significant physical climate risk considering the facilities residual useful lives and assets features and barriers. Therefore, this activity does not significantly harm the objective of climate change adaptation.

Transition to a circular economy

The activity has assessed availability of and, where feasible, it is using equipment and components of high durability and recyclability and that are easy to dismantle and refurbish.

Protection and restoration of biodiversity and ecosystem

Eni's PV installations have obtained before the start of construction works an Environmental Impact Assessment in compliance with Directive 2011/92/EU or a proper authorization based on an equivalent environmental assessment in case of installations located outside EU. Therefore, this activity does not significantly harm the objective of the protection and restoration of biodiversity and ecosystem.

4.3. Electricity generation from wind power

Substantial contribution to climate change mitigation

The activity generates electricity from wind power.

DNSH

Climate change adaptation

Based on the assessment of this activity's exposure to climate-related hazards following the methodology and procedures described herein, the management has concluded that the Company's PV windmills are not exposed to any significant physical climate risk considering the facilities residual useful lives and assets features and barriers. Therefore, this activity does not significantly harm the objective of climate change adaptation.

Transition to a circular economy

The activity has assessed availability of and, where feasible, it is using equipment and components of high durability and recyclability and that are easy to dismantle and refurbish.

Protection and restoration of biodiversity and ecosystem

Eni's windmills have obtained before the start of construction works an Environmental Impact Assessment in compliance with Directive 2011/92/EU or a proper authorization based on an equivalent environmental assessment in case of installations located outside EU. Therefore, this activity does not significantly harm the objective of the protection and restoration of biodiversity and ecosystem.

4.8. Electricity generation from bioenergy

Substantial contribution to climate change mitigation

Eni's activity comprises electricity generation installations each with a total rated thermal input below 2 MW, which are using gaseous biomass fuels. The installations are located in Italy.

DNSH

Climate change adaptation

Based on the assessment of this activity's exposure to climate-related hazards following the methodology and procedures described herein, the management has concluded that the Company's electricity generation installations are not exposed to any significant physical climate risk. Therefore, this activity does not significantly harm the objective of climate change adaptation.

Sustainable use and protection of water and marine resources

Protection and restoration of biodiversity and ecosystem

Eni's electricity generation installations have obtained before the start of construction works an Environmental Impact Assessment in compliance with Directive 2011/92/EU. Therefore, this activity does not significantly harm the objectives of the sustainable use and protection of water and marine resources and of protection and restoration of biodiversity and ecosystem.

4.13. Manufacture of biogas and biofuels for use in transport and of bioliquids

The activity consists in manufacturing HVO for use in transport. The activity is performed at the biorefineries of Gela (Sicily) and Venice.

Substantial contribution to climate change mitigation

Each batch of HVO manufactured in 2023 has been reviewed to assess the substantial contribution to climate change mitigation. Volumes of HVO manufactured using food and feed crops as feedstock have been excluded from the KPI, as well as those produced using agricultural biomass that does not comply with the criteria laid down in Article 29, paragraphs 2 to 5, of Directive (EU) 2018/2001.

The greenhouse gas emission savings from the HVO volumes manufactured from sustainable feedstock have been measured by applying the GHG saving methodology and the relative fossil fuel comparator set out in Annex V to Directive (EU) 2018/2001.

The saving has been calculated for each kind of biomass used as feedstock. Based on the outcome of this review, 95% of the marketed to third parties volumes at the Gela biorefinery have been assessed to contribute substantially to climate change mitigation.

The activity turnover, OpEx, and Capex have apportioned to the relevant KPIs in proportion to the percentage of environmentally sustainable manufactured volumes of HVO.

DNSH

Climate change adaptation

Based on the assessment of this activity's exposure to climate-related hazards following the methodology and procedures described herein, the management has concluded that the Company's biorefinery of Gela exposed to a risk of water stress. The water risk monitoring plan is ongoing.

A monitoring plan is being implemented to check how the risk exposure evolves over time with the goal of adapting the activity to climate change within five years.

Sustainable use and protection of water and marine resources

Protection and restoration of biodiversity and ecosystem

Eni's biorefineries have obtained before the start of construction works and subsequently on occasion of any major upgrading, reconfiguration or restructuring an Environmental Impact Assessment in compliance with Directive 2011/92/EU. Therefore, this activity does not significantly harm the objectives of the sustainable use and protection of water and marine resources and of protection and restoration of biodiversity and ecosystem.

5.12. Underground permanent geological storage of CO2

The activity consists in building and operating the permanent underground Hyte hub to store CO2 by leveraging Eni's depleted reservoirs, off the Liverpool Bay in UK. The storage service will be made available to local businesses in hard-to-abate industries according to a regulated tariff which is currently under negotiation. Italian authorities approved a pilot project to build and operate a plant for the storage of CO2 utilizing the depleted natural gas fields of Eni offshore Ravenna in the Adriatic Sea.

Substantial contribution to climate change mitigation

The UK activity complies with ISO 27914:2017 for geological storage of CO2. The Italian activity complies with provisions of Directive 2009/31/EC.

DNSH

Climate change adaptation

Based on the assessment of this activity's exposure to climate related hazards following the methodology and procedures described herein, the management has concluded that it is adapted to climate change.

Pollution prevention and control

The management foresees that by adopting the risk management systems and the procedures of monitoring & verification provided by the above-mentioned ISO rules, the activity will comply with the pollution thresholds and markers set by Directive 2009/31/C.

Sustainable use and protection of water and marine resources

Protection and restoration of biodiversity and ecosystem

The management foresees that by adopting the risk management systems and the monitoring&verification procedures provided by the abovementioned ISO rules and by implementing all of the planned measures to ensure the environmental sustainability of the project to be granted all necessary authorizations by the relevant UK authorities, the DNSH criteria will be met with respect to the objectives of Sustainable use and protection of water and marine resources and of Protection and restoration of biodiversity and ecosystem.

6.15. Infrastructure enabling low carbon road transport and public transport

Substantial contribution to climate change mitigation

The activity consists in installing and operating a network of electric charging points for EV and it is an enabling activity.

DNSH

Climate change adaptation

The Group has conducted a risk assessment of the activity 'exposure to acute and chronic weather events as outlined in Appendix A of the Delegated Act on climate, based on the methodology described at point 4.1. It has concluded that the before mentioned infrastructure, even considering their remaining useful life, does not present substantial residual risks of exposure to prospective adverse weather events. Therefore, the activity has been assessed as suitable for Climate Change (CC). The assessment was carried out for geographic macro-areas sharing the same type of climate risks. In general, the activity's exposure to physical risks is limited, both due to the territorial dispersion of the facilities and considerations related to the intangible contribution of each installation and the promptness of potential recovery times.

Pollution prevention and control

In the installation of electric charging points, the Company limits waste generation in processes related construction and demolition, in accordance with the EU Construction and Demolition Waste Management Protocol and taking into account best available techniques and using selective demolition to enable removal and safe handling of hazardous substances and facilitate reuse and high-quality recycling by selective removal of materials, using available sorting systems for construction and demolition waste.

Measures are taken to reduce noise, dust and pollutant emissions during construction or maintenance works, such as for example:

1. utilization of equipment with low environmental impact, which reduces noise, dust and pollutant emissions compare to traditional equipment;

2. limiting working hours by scheduling, when and where possible, construction or maintenance activities during the hours when there is less traffic to limit the impact on surrounding activities.

Sustainable use and protection of water and marine resources

Protection and restoration of biodiversity and ecosystem

Eni's electric charging points have obtained before the start of construction works an Environmental Impact Assessment in compliance with Directive 2011/92/EU. Therefore, this activity does not significantly harm the objectives of the sustainable use and protection of water and marine resources and of protection and restoration of biodiversity and ecosystem.

The installation of charging points for electric vehicles complies with specific laws and technical rules to ensure the safety of users and the integrity of the infrastructure, which also include the protection of biodiversity/ecosystems.

1.2.2.2. Contribution to multiple objectives

Not applicable.

1.2.2.3. Disaggregation of KPIs

In the activity 4.13 manufacture of biofuels for use in transport, the biorefinery of Gela is a common facility for both the production of Taxonomy-aligned biofuels and for Taxonomy-eligible biofuels. The facility common costs have been apportioned to each activity in proportion to the manufactured volumes of biofuels.

The management believes that such disaggregation is based on criteria that are appropriate for the production process being implemented and reflects the technical specificities of that process.

1.2.3. Contextual information

1.2.3.1. Contextual information about turnover KPI

The amounts that sum up the numerator of the turnover KPI have derived from contracts with customers and were recognized based on IFRS 15. The total amount of the numerator was €1,119 million and the break-down is as follows:

• €192 million from the sale of electricity generated by the Group's PV installations;

• €168 million from the sale of electricity generated by the Group's windmills;

• €35 million from the sale of electricity generated by installations using gaseous biomass fuels;

• €660 million from the sale of biofuels (HVO);

• €59 million from the sale of plastics in primary form in connection with the completed acquisition in the fourth quarter of 2023 of the Novamont group.

The 36% increase in revenues from customers compared to 2022 was driven by a ramp-up in sales volumes of renewable electricity.

1.2.3.2. Contextual information about CapEx KPI

The numerator of the CapEX KPI amounted to €2,012 million and comprised:

• €606 million related to the activity of electricity generation using solar photovoltaic technology, including: i) €214 million in asset increases for progress in the construction program, of which €71 million is related to the new installed capacity in 2023 for 153 MW, and ii) €392 million in acquisitions, of which €132 million pertains to third-party facilities acquired during the fiscal year, resulting in an operational capacity of 177 MW, and €259 million for ready-to-build facilities with planned capacity in operation in the 2024-2027 timeframe;

• €138 million related to the activity of production of electricity from wind energy, including: i) €70 million in asset increases for progress in the construction program, of which €20 million is related to new installed capacity in 2023 for 57 MW, and ii) €68 million in acquisitions of ready-tobuild facilities with planned capacity in operation in the 2024-2027 timeframe;

• €745 million related to the acquisition of control of the Novamont Group, whose activities in the production of resins and plastics from renewable feedstocks have been assessed as aligned with the Taxonomy. The amount relates to the amount of the purchase price allocated to intangible assets and plant and equipment.

• €224 million related to the activity of production of biofuels, relating to the increase in Property, Plant, and Equipment (PP&E), at the biorefineries in Venice and Gela, with €121 million for Venice and €86 million for Gela. Cost incurred for €17 million were capitalized as part of the conversion project of oil-based Livorno refinery into a biorefinery. In Venice, various projects are underway for upgrading the biorefinery, with the main ones involving the establishment of a new section (degumming) in the biomass treatment unit to enhance the processing of more complex feedstocks. Other projects include the adaptation of the ecofining plant to produce biofuels from feedstocks pretreated by degumming, and the construction of a steam reforming plant and its interconnecting infrastructure. This plant will replace the gasoline cycle for supplying the necessary hydrogen to produce HVO, resulting in an increased processing capacity of up to 0.6 million tons per year, with completion expected in 2025.

Regarding Gela, the main projects involved the upgrading of the biomass treatment unit (BTU) to enhance the processing of more complex feedstocks and the construction of a plant for biojet production. Both projects are expected to be completed in the second half of 2024. These biorefinery projects are part of Eni's industrial investment plan for the '24-'27 four-year period, approved by the Board of Directors on March 13, 2024, and they represent some of the drivers that the Group has activated to achieve the goal of reaching a capacity of over 3 million tons per year by 2026.

• €145 million relating to the activity of underground permanent storage of CO2, fully consisting of additions to intangible assets as part of an ongoing project to build and operate the Hynet and Bacton storage hub in UK and a pilot project to develop a CO2 storage hub off Ravenna, Italy. Both projects have been included in the Group four-year capital budget that was approved by the Board of Directors on March 13, 2024. Total capital expenditures for the Hynet project are estimated at €279 million in the four-year plan, expected in the second half of the decade when the first volume of CO2 is forecast to be injected in the depleted reservoirs operated by Eni, offshore the Liverpool Bay, while the Bacton project involves a planned expenditure of €30 million, with the first CO2 injection scheduled by 2030. The expected expenditures for the Italian hub amount to €32million in the four-year plan, with expected startup by 2030 after an experimental period in the course of 2024 at industrial scale within the term of five years;

• €121 million relating to the activity of installing recharging points for EV, allocated to increases in PP&E by €119 million and intangible assets by €2 million, within the framework of the charging network expansion plan with the installation of approximately 5,900 new charging stations under the Plenitude brand in 2023;

• €23 million in investments for the development of storage projects, including: i) €11 million in asset increases for progress in the construction program, and ii) €12 million in acquisitions.

1.2.3.3. Contextual information about the OpEx KPI

The numerator of the OpEx KPI comprises €190 million of expenses that mainly related to maintenance and repair, and other direct expenditures relating to the day-to-day servicing of assets of property, plant and equipment by the Eni or third party to whom activities are outsourced that were necessary to ensure the continued and effective functioning of such assets. The breakdown related to the main activities is as follows:

• €86 million incurred in the production of electricity from photovoltaic plants, related to maintenance and other daily operating expenses (inspections, cleaning, and others);

• €25 million incurred in the production of electricity from wind plants, related to maintenance and other daily operating expenses (inspections, cleaning, and others);

• €64 million incurred in the production of biofuels, related to maintenance and other daily operating expenses (inspections, cleaning, and others).

Compliance with the Minimum Safeguards (Ms) - Article 3 "c" of the EU Taxonomy Regulation

The criteria for the eco-sustainability of economic activities outlined in article 3 of the Taxonomy Regulation call for respecting minimum safeguards when conducting business (referred to in paragraph "c"). The rule under Article 18 identifies the MS with the procedures implemented by a company to ensure that business conduct complies with the OECD Guidelines for Multinational Enterprises and the United Nations Guiding Principles on Business and Human Rights. Compliance with the MS includes the principles and rights set out in the eight core conventions identified in the International Labour Organisation's Declaration on Fundamental Principles and Rights at Work and in the International Bill of Human Rights.

When companies implement these procedures, they must also comply with the "do no significant harm" principle outlined in Article 2, paragraph 17 of Regulation (EU) 2019/2088, the Sustainable Finance Disclosure Regulation (SFDR). The SFDR requires financial market participants to assess the ESG risk of the investments within the financial products they intend to offer investors, measuring the ESG performance of the investee companies against a predefined set of key impact indicators in critical "principal adverse impact" areas. Five of these indicators have a social nature: (i) violations of the UN Global Compact principles and the OECD Guidelines for Multinational Enterprises; (ii) lack of processes and compliance mechanisms to monitor compliance with the previous point's principles; (iii) unadjusted gender pay gap; (iv) Board gender diversity; and (v) exposure to controversial weapons. The definition of sustainable investment in article 2 (17) of the SFDR states that an investment is sustainable if it contributes to broadly defined environmental or social objectives, provided that it does not harm any of these objectives. Thus, Eni assumes that in complying with the SFDR principle "do no significant harm", it is understood to refer to the five social impact indicators described above, four of which are included in Eni's human rights due diligence processes. Regarding the fifth, Eni confirms that it does not have any exposure to controversial weapons.

The OECD Guidelines for Multinational Enterprises are principles for responsible business conduct related to eight business areas:

• three relate to the issues of human rights (human rights, consumer protection, employment and industrial relations);

• Anti-Corruption;
• fair competition;
• taxation.

Finally, environmental protection is treated by the sustainability performance criteria set article 3 of the Taxonomy Regulation, while science/technology are out of the scope.

The ILO's eight labor conventions are comprised in the wider issue of respect for human rights.

Observance of the fundamental principles of human rights contained in the International Bill of Human Rights (Universal Declaration of Human Rights, International Covenant on Civil and Political Rights and International Covenant on Economic Social and Cultural Rights) is ensured by Eni's compliance with the Italian Constitution and rules intended to implement it, which embody human rights principles. As a company incorporated in Italy, Eni is obliged to observe them.

Compliance with the safeguard clause is based on establishing and maintaining adequate company due diligence processes and company's management systems in the following areas:

• human rights;
• Anti-corruption;
• compliance with competition law;
• business taxation.

Furthermore, evidence of compliance with the MS is given by absence of legal proceedings against each of the Group companies or members of its top management for violations of national or international laws relating to such matters that have resulted in final convictions; or the absence of complaints or reports of alleged human rights violations submitted by individual stakeholders or groups of stakeholders to an OECD National Contact Point or to the Business and Human Rights Resource Centre, in the wake of which the Company has not demonstrated concrete commitment to addressing and managing the report, failing to cooperate in its resolution and/or to adopt a remediation plan in the event it is responsible for causing and/or contributing to the negative impact of the complaint.

Eni's due diligence systems:

• ANTI-CORRUPTION. Within the context of the Company's zero tolerance for corruption, Eni has adopted a controlled environment that includes processes and controls designed to minimize the risk of behavior or transactions that could lead to willful or negligent acts of corruption. This aims to ensure constant and strict compliance of Eni's employees, contractors and other individuals working or acting on behalf of Eni with the anti-corruption laws in force in the countries where the Company operates. This system also applies to money laundering. The control environment is based on values the organization shares, starting with top management. It includes establishing a code of ethics inspired by the principles of transparency, honesty, fairness, and good faith in conducting business, adherence to the UN Ten Principles of Corporate Responsibility, participation in the Global Compact and personnel training on ethical issues. The processes and controls are designed to ensure accurate and transparent recording of corporate transactions, assessment of economic counterparties in significant transactions (acquisitions/divestment of subsidiaries, shareholdings and assets, mining rights, business combinations, etc.), involvement of certain types of counterparties (business associates, joint venture partners, brokers) or in areas (trading, non-profit initiatives, sponsorships) exposed to corruption risks, as well as compliance of business conduct with internal rules under all circumstances where a breach of the code of ethics might be possible, to prevent any form of corruption in managing the business. An integral part of Eni's DD on Anti-Corruption is establishing and maintaining a whistleblowing mechanism even for managing anonymous reports received by the Company through a wellidentified and recognizable channel of alleged violations of anti-corruption and money laundering regulations (this mechanism also applies to the DD on Human Rights). In 2023, neither the Company nor members of senior management were party to criminal proceedings for violating anti-corruption regulations that resulted in a final verdict of conviction. Please refer to the notes to the consolidated financial statements for more information on the status of the Group's legal proceedings.

• TAXATION. Eni has adopted a due diligence system for managing relations with the tax authorities of the countries in which it operates. The aim is to minimize the risk that business operations violate applicable tax regulations. The Company's tax guidelines provide for the payment of taxes in the countries where operations take place according to the merit as well as the letter of local rules and rejects aggressive tax policy choices, including delocalization of economic activities to so-called tax havens. The Company has a Tax Control Framework, i.e. a specific tax risk control system. Management is responsible for verifying consistency between tax management choices and the Board-approved strategy. The control environment and processes/procedures are designed to mitigate the risk of violations which could trigger significant financial or reputational impact (tax risk). In 2023, no Group company was party to any tax dispute for violations of tax rules or tax fraud resulting in a final verdict of conviction. For more information on the status of the Group's tax litigation, please refer to the notes to the consolidated financial statements. These disputes relate to the technical interpretation of local tax regulations, which are often very complex. They are managed with a view to reconciliation.

• FAIR COMPETITION. Eni has set up a controlled environment and a set of procedures and controls to minimize the risk that business and corporate activities violate the rules protecting competition in the various countries where it operates. Among the fundamental values of the Company are the principles of fair competition – understood as a market environment that encourages companies to excel in the quality and cost effectiveness of the products and/or services sold/supplied – and compliance with antitrust legislation. Eni's control system has three phases: prevention, risk monitoring/mitigation and counteracting unlawful conduct. It is designed to minimize the risk that Eni's business units and subsidiaries engage in anti-competitive conduct, adopt practices that restrict the free market or collude with competing companies. Corporate transactions to increase market share (mergers/acquisitions) are executed after the antitrust authorities of the jurisdictions concerned have been informed. Appropriate remediation plans are formulated in response to any comments received and in compliance with standstill obligations and the prohibition of unlawful exchange of information during the negotiation and due diligence phases. In 2023, no Group company or senior management member was party to disputes for antitrust legislation violations that resulted in a final verdict of conviction. On the reporting date, there was no significant pending antitrust disputes.

• HUMAN RIGHTS. Human rights are at the heart of Eni's vision as a responsible company and a core component of the organization's values, culture, and management systems. Eni is committed to respecting human rights in all business activities and places similar expectations on business partners operating on behalf of Eni or who are contracted over the course of Eni's industrial activities. Eni has adopted a human rights due diligence process that complies with the OECD Guidelines for Multinational Enterprises, including OECD guidelines on Human Rights DD, and the United Nations Guiding Principles on Business and Human Rights (UNGP).

Eni is committed to carrying out Human Rights Due Diligence in its activities and has adopted a model that identifies and assesses risks relating to the potential violation of Human Rights from a dual perspective:

• The risk of causing (or contributing to causing) actual or potential adverse impacts on Human Rights, with reference to the UNGPs and the OECD Guidelines.
• The risk of incurring sanctions, significant financial losses, or reputational damage.

Eni assesses the Human Rights potential and actual impacts of its activities on an ongoing basis and identifies specifically tailored strategies and solutions, in the context of an ongoing effort to improve prevention and mitigation of such impacts.

In line with OECD/UNGP guidelines, Eni's DD on human rights is structured along six steps:

• i) adoption of a commitment statement, by the top management, upholding respect for human rights and the integration of human rights into company management systems, processes and policies.
• ii) recognition of value chain stages and business relationships where Eni is most exposed to risks of human rights violation leading to identification of Salient Human Rights Issues for Eni, that are defined based on the business activities, the contexts in which Eni operates and the sharing with relevant local and international stakeholders, through the adoption of a risk-based approach.
• iii) a risk assessment aiming to identify and evaluate the adverse impacts of the company's activities on human rights, which foresees the involvement of stakeholders;
• iv) the design and implementation of measures to prevent, cease or mitigate any adverse impact;
• v) the verification of the effectiveness of the measures taken;
• vi) reporting on outcomes and impacts relating to actions undertaken by the company to prevent, cease or mitigate the adverse impact and the measures taken, which targets interested stakeholders and provides useful inputs to improve planning of future company's activities.

In line with OECD guidelines, Eni has established a mechanism for collecting and evaluating complaints and concerns brought to the Company's attention through appropriate channels for listening and for the receipt of communications by individuals, communities, or associations of individuals, aimed at ensuring that any possible violations of Human Rights are promptly detected, scrutinized, managed and – where ascertained – remedied.

In the event of alleged Human Rights violation the company provides two schemes of access to the Company:

• a "Grievance Mechanism", which includes a set of procedures that Eni makes available for the receipt and treatment of alleged violations, which include the options to lodge, in written or verbal form, complaints or grievances on part of affected stakeholders in relation to the Eni's business activities and on their management and resolution. Human rights grievances qualified as "significant" entail a specific procedure for their scrutiny and response.
• "Reporting", which includes the channels available to employees or third parties to report, even confidentially or anonymously, issues concerning the Internal Control System or alleged violations of the principles stated in Eni's Code of Ethics, such as business ethics, bullying, harassment, discrimination, and respect for Human Rights.

Eni also cooperates with other non-judicial redress mechanisms, such as the one provided and regulated by the OECD Guidelines and set up at OECD National Contact Points.

Eni is actively committed to reviewing complaints and providing or cooperating to provide remedies for adverse human rights impacts that it may have caused or contributed to, and to make every effort to promote the achievement of the same objective in cases where the impact is directly related to its operations. Eni cooperates actively and in good faith with other access facilities to reach a judicial or non-judicial resolution to open issues. In no case does Eni prohibit potential claimants access to remediation measures. The company is committed to preventing reprisals against workers and other stakeholders for raising human rights concerns. It does not tolerate or contribute to threats, intimidation, reprisals or attacks against human rights defenders and stakeholders involved with its operations.

An integral part of due diligence is the communication of the obtained results. Eni publishes a yearly report "Eni for" sustainability, which includes a dedicated section to human rights reporting to inform and update stakeholders on progress made to address human rights issues.

In 2023, Eni did not receive any final verdict of conviction for violations of laws, regulations or other regulatory institutions relating to human rights, bribery, competition or tax violations. The Company is cooperating actively and in good faith with the OECD National Contact Points to resolve pending Specific Instances.

On the matter of human rights, Eni ranked second among energy companies in the 2023 Corporate Human Rights Benchmark promoted by the World Benchmark Alliance.

In conclusion, considering the draft Report "Minimum Safeguards", Eni believes it complies with the safeguard clause of Article 3, paragraph "c" of the EU Taxonomy Regulation.

Turnover KPI		Financial year 2023			Substantial contribution criteria DNSH
Economic activities (1)	Code(s) (2)	Absolute Turnover (3)	Proportion of Turnover (4)	Climate Change Mitigation (CCM) (5)	Climate Change Adaptation (CCA) (6)	Water and marine resources (7)	Circular economy (8)	Pollution (9)	Biodiversity and ecosystems (10)	Climate Change Mitigation (CCM) (11)	Climate Change Adaptation (CCA) (12)	Water and marine resources (13)	Circular economy (14)	Pollution (15)	Biodiversity and ecosystems (16)	Minimum Safeguards (17)	Proportion of Taxonomy aligned or eligible Turnover year 2022 (18)	Category (enabling activity or) (20)	Category (transitional activity) (21)
		m€	%	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y/N	Y/N	Y/N	Y/N	Y/N	Y/N	Y/N	%	E	T
A. TAXONOMY-ELIGIBLE ACTIVITIES
A.1. Environmentally sustainable activities (Taxonomy-aligned)
Manufacture of plastics in primary form	CCM 3.17	59	0.1%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%		T
Electricity generation using solar photovoltaic technology	CCM 4.1	192	0.2%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Electricity generation (wind)	CCM 4.3	168	0.2%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.1%
Electricity generation from bioenergy	CCM 4.8	35	0.0%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Manufacture of biogas and biofuels for use in transport and of bioliquids	CCM 4.13	660	0.7%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.5%
Anaerobic digestion of bio-waste	CCM 5.7/CE 2.5	3	0.0%	Y	N/EL	N/EL	N	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Composting of bio-waste	CCM 5.8/CE 2.5	2	0.0%	Y	N/EL	N/EL	N	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Turnover of environmentally sustainable activities (Taxonomy-aligned) (A.1)		1,119	1.2%	%							Y	Y	Y	Y	Y	Y	%	0	0
Of which Enabling			0.0%														0.0%	E
Of which Transitional A.2. Taxonomy-Eligible but not environmentally sustainable activities (not Taxonomy-aligned)			0.1%														0.0%		T
Manufacture of plastic packaging goods	CE 1.1	7	0.0%	N/EL	N/EL	N/EL	EL	N/EL	N/EL							Y	0.0%
Recovery of bio-waste by anaerobic digestion or composting	CE 2.5	5	0.0%	EL	N/EL	N/EL	EL	N/EL	N/EL							Y	0.0%
Manufacture of organic basic chemicals	CCM 3.14	1,323	1.4%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	1.6%
Manufacture of plastics in primary form	CCM 3.17	1,583	1.7%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	1.6%
Transmission and distribution of electricity	CCM 4.9	7	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Manufacture of biogas/biofuels for use in transport	CCM 4.13	84	0.1%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Cogeneration of heat/cool and power from bioenergy	CCM 4.20	1	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
High-efficiency co-generation of heat/cool and power from fossil gaseous fuels	CCM 4.30	2,105	2.2%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	3.5%
Construction, extension and operation of waste water collection and treatment	CCM 5.3	12	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Collection and transport of non-hazardous waste in source segregated fractions	CCM 5.5	2	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Transport by motorbikes, passenger cars and commercial vehicles	CCM 6.5	23	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Turnover of Taxonomy-eligible but not environmentally sustainable activities (not Taxonomy-aligned activities) (A.2)		5,147	5.5%	%	%	%	%	%	%							Y	%
Turnover of Taxonomy eligible activities (A1 + A2)		6,266	6.7%														%
B. TAXONOMY-NON-ELIGIBLE ACTIVITIES
Turnover of Taxonomy-non-eligible activites (B)		87,451	93.3%
TOTAL			93,717 100.0%

Capex KPI		Financial year 2023				Substantial contribution criteria				DNSH
Economic activities (1)	Code(s) (2)	Absolute CapEx (3)	Proportion of CapEx (4)	Climate Change Mitigation (CCM) (5)	Climate Change Adaptation (CCA) (6)	Water and marine resources (7)	Circular economy (8)	Pollution (9)	Biodiversity and ecosystems (10)	Climate Change Mitigation (CCM) (11)	Climate Change Adaptation (CCA) (12)	Water and marine resources (13)	Circular economy (14)	Pollution (15)	Biodiversity and ecosystems (16)	Minimum Safeguards (17)	Proportion of Taxonomy aligned or eligible CapEx year 2022 (18)	Category (enabling activity or) (20)	Category (transitional activity) (21)
		m€	%	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y/N	Y/N	Y/N	Y/N	Y/N	Y/N	Y/N	%	E	T
A. TAXONOMY-ELIGIBLE
ACTIVITIES A.1. Environmentally sustainable activities (Taxonomy-aligned)
Manufacture of hydrogen	CCM 3.10	2	0.0%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Manufacture of plastics in primary form	CCM 3.17	745	5.5%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%		T
Electricity generation using solar photovoltaic technology	CCM 4.1	606	4.4%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	4.9%
Electricity generation (wind)	CCM 4.3	138	1.0%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	7.3%
Electricity generation from bioenergy	CCM 4.8	2	0.0%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Storage of electricity	CCM 4.10	23	0.2%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Manufacture of biogas and biofuels for use in transport and of bioliquids	CCM 4.13	224	1.6%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.8%
Underground permanent geological storage of CO2	CCM 5.12	145	1.1%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.6%
Transport by motorbikes, passenger cars and commercial vehicles	CCM 6.5	6	0.0%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%
Infrastructure enabling road transport and public transport	CCM 6.15	121	0.9%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.5%	E
CapEx of environmentally sustainable activities (Taxonomy-aligned) (A.1)		2,012	14.7%	%							Y	Y	Y	Y	Y	Y	%	0	0
Of which Enabling Of which Transitional			0.9% 5.5%														0.5% 0.0%	E	T
A.2. Taxonomy-Eligible but not environmentally sustainable activities (not Taxonomy-aligned)
Manufacture of organic basic chemicals	CCM 3.14	66	0.5%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.9%
Manufacture of plastics in primary form	CCM 3.17	78	0.6%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.6%
Transmission and distribution of electricity	CCM 4.9	2	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Manufacture of biogas/biofuels for use in transport	CCM 4.13	76	0.6%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.2%
High-efficiency co-generation of heat/cool and power from fossil gaseous fuels	CCM 4.30	101	0.7%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	1.2%
Construction, extension and operation of waste water collection and treatment	CCM 5.3	32	0.2%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.4%
Transport by motorbikes, passenger cars and commercial vehicles	CCM 6.5	10	0.1%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.1%
Infrastructure enabling road transport and public transport	CCM 6.15	6	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
CapEx of Taxonomy-eligible but not environmentally sustainable activities (not Taxonomy-aligned activities) (A.2)		371	2.7%	%	%	%	%	%	%							Y	%
Capex of Taxonomy eligible activities (A1 + A2)		2,383	17.4%														%
B. TAXONOMY-NON-ELIGIBLE ACTIVITIES
Capex of Taxonomy-non-eligible activites (B) TOTAL		11,282	82.6% 13,665 100.0%

OpEx KPI		Financial year 2023				Substantial contribution criteria				DNSH
Economic activities (1)	Code(s) (2)	Absolute OpEX (3)	Proportion of OpEX (4)	Climate Change Mitigation (CCM) (5)	Climate Change Adaptation (CCA) (6)	Water and marine resources (7)	Circular economy (8)	Pollution (9)	Biodiversity and ecosystems (10)	Climate Change Mitigation (CCM) (11)	Climate Change Adaptation (CCA) (12)	Water and marine resources (13)	Circular economy (14)	Pollution (15)	Biodiversity and ecosystems (16)	Minimum Safeguards (17)	Proportion of Taxonomy aligned or eligible OpEX year 2022 (18)	Category (enabling activity or) (20)	Category (transitional activity) (21)
		m€	%	Y; N; N/EL (b) (c)	Y; N; N/EL (b) (c)	Y; N; N/EL (b)	Y; N; N/EL (b)	Y; N; N/EL (b)	Y; N; N/EL (b) (c)	Y/N	Y/N	Y/N	Y/N	Y/N	Y/N	Y/N	%	E	T
A. TAXONOMY-ELIGIBLE						(c)	(c)	(c)
ACTIVITIES A.1. Environmentally
sustainable activities (Taxonomy-aligned) Manufacture of plastics in	CCM
primary form Electricity generation using	3.17	5	0.1%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.0%		T
solar photovoltaic technology	CCM 4.1	86	2.2%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.4%
Electricity generation (wind)	CCM 4.3	25	0.6%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.7%
Electricity generation from bioenergy	CCM 4.8	8	0.2%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.1%
Manufacture of biogas and biofuels for use in transport and of bioliquids	CCM 4.13	64	1.6%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.6%
Anaerobic digestion of bio waste	CCM 5.7	2	0.1%	Y	N/EL	N/EL	N/EL	N/EL	N/EL		Y	Y	Y	Y	Y	Y	0.1%
OpEX of environmentally sustainable activities		190	4.8%	%							Y	Y	Y	Y	Y	Y	%		0
(Taxonomy-aligned) (A.1) Of which Enabling			0.0%														0.0%	E
Of which Transitional A.2. Taxonomy-Eligible but			0.1%														0.0%		T
not environmentally sustainable activities (not
Taxonomy-aligned) Manufacture of other low carbon technologies	CCM 3.6	8	0.2%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.6%
Manufacture of organic basic chemicals	CCM 3.14	57	1.4%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	1.7%
Manufacture of plastics in primary form	CCM 3.17	69	1.7%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	1.6%
Electricity generation using solar photovoltaic	CCM 4.1	0	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.3%
technology Electricity generation (wind)	CCM 4.3	0	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Electricity generation from ocean energy technologies	CCM 4.4	0	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.2%
Transmission and distribution of electricity	CCM 4.9	2	0.1%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.0%
Storage of electricity	CCM 4.10	0	0.0%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.1%
Manufacture of biogas/biofuels for use in transport	CCM 4.13	17	0.4%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.7%
Cogeneration of heat/cool and power from bioenergy	CCM 4.20	13	0.3%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.2%
High-efficiency co-generation of heat/cool and power from fossil gaseous fuels	CCM 4.30	46	1.2%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	1.2%
Construction, extension and operation of waste water collection and treatment	CCM 5.3	140	3.5%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	3.3%
Collection and transport of non-hazardous waste in	CCM 5.5	8	0.2%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.1%
source segregated fractions Underground permanent geological storage of CO2	CCM 5.12	3	0.1%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.2%
Transport by motorbikes, passenger cars and	CCM 6.5	5	0.1%	EL	N/EL	N/EL	N/EL	N/EL	N/EL							Y	0.1%
commercial vehicles OpEX of Taxonomy-eligible but not environmentally sustainable activities (not Taxonomy-aligned		368	9.2%	%	%	%	%	%	%							Y	%
activities) (A.2) OpEX of Taxonomy eligible activities (A1 + A2)		558	14.0%														%
B. TAXONOMY-NON-ELIGIBLE ACTIVITIES
OpEX of Taxonomy-non eligible activites (B) TOTAL		3,421 3,979	86.0% 100.0%

	Template 1: Nuclear and fossil gas related activities,2023
Row	Nuclear energy related activities	2023
1	The undertaking carries out, funds or has exposures to research, development, demonstration and deployment of innovative electricity generation facilities that produce energy from nuclear processes with minimal waste from the fuel cycle.	No
2	The undertaking carries out, funds or has exposures to construction and safe operation of new nuclear installations to produce electricity or process heat, including for the purposes of district heating or industrial processes such as hydrogen production, as well as their safety upgrades, using best available technologies.	No
3	The undertaking carries out, funds or has exposures to safe operation of existing nuclear installations that produce electricity or process heat, including for the purposes of district heating or industrial processes such as hydrogen production from nuclear energy, as well as their safety upgrades.	No
	Fossil gas related activities
4	The undertaking carries out, funds or has exposures to construction or operation of electricity generation facilities that produce electricity using fossil gaseous fuels.	Yes
5	The undertaking carries out, funds or has exposures to construction, refurbishment, and operation of combined heat/cool and power generation facilities using fossil gaseous fuels.	No
6	The undertaking carries out, funds or has exposures to construction, refurbishment and operation of heat generation facilities that produce heat/cool using fossil gaseous fuels.	No

Template 2: Taxonomy-aligned economic activities

			Turnover					Capex				Opex
	RowEconomic activities	CCM + CCA		Climate change mitigation (CCM)		Climate change adaptation (CCA) Amount % Amount % Amount % Amount % Amount % Amount % Amount % Amount % Amount %		CCM + CCA	Climate change mitigation (CCM)		Climate change adaptation (CCA)	CCM + CCA		Climate change mitigation (CCM)	Climate change adaptation (CCA)
1	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.26 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
2	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.27 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
3	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.28 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
4	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.29 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
5	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.30 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI	0	0%0		0%0	0%0		0%0		0%0	0%0		0%0	0%0	0%
6	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.31 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
7	Amount and proportion of other taxonomy-aligned economic activities not referred to in rows 1 to 6 above in the denominator of the applicable KPI	1,119		1.2%1,119	1.2%0	0%	2,012	14.7%2,012		14.7%0		0%190	4.8%190	4.8%0	0%
	8 Total applicable KPI			93,717 100%93,717 100%0					0%13,665 100%13,665 100%0			0%3,979	100%3,979	100%0	0%

Template 3: Taxonomy-aligned economic activities (numerator),2023 € million, except where indicated

Row	Economic activities	CCM + CCA		Turnover Climate change mitigation		Climate change adaptation	CCM + CCA	Capex Climate change mitigation	Climate change adaptation	CCM + CCA	Opex Climate change mitigation	Climate change adaptation
					(CCM)	(CCA)		(CCM)	(CCA)		(CCM)	(CCA)
		Amount	%	Amount	%	Amount % Amount	%	Amount %	Amount % Amount	%	Amount %	Amount %
1	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.26 of Annexes I and II to Delegated Regulation 2021/2139 in the numerator of the applicable KPI
2	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.27 of Annexes I and II to Delegated Regulation 2021/2139 in the numerator of the applicable KP
3	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.28 of Annexes I and II to Delegated Regulation 2021/2139 in the numerator of the applicable KPI
4	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.29 of Annexes I and II to Delegated Regulation 2021/2139 in the numerator of the applicable KPI
5	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.30 of Annexes I and II to Delegated Regulation 2021/2139 in the numerator of the applicable KPI	0	0%0		0%0	0%0		0%0	0%0 0%0	0%0	0%0	0%
6	Amount and proportion of taxonomy-aligned economic activity referred to in Section 4.31 of Annexes I and II to Delegated Regulation 2021/2139 in the numerator of the applicable KPI
7	Amount and proportion of other taxonomy aligned economic activities not referred to in rows 1 to 6 above in the numerator of the applicable KPI	1,119	100.0%1,119		100.0%0		0%2,012	100.0%2,012 100.0%0		0%190 100.0%190	100.0%0	0%
8	Total amount and proportion of taxonomy aligned economic activities in the numerator of the applicable KPI	1,119	100.0%1,119		100.0%0		0%2,012	100.0%2,012 100.0%0		0%190 100.0%190	100.0%0	0%

Template 4: Taxonomy-eligible but not taxonomy-aligned economic activities,2023 € million, except where indicated

					Turnover			Capex		Opex
	RowEconomic activities		CCM + CCA		Climate change mitigation (CCM)	Climate change adaptation (CCA)	CCM + CCA	Climate change mitigation (CCM)	Climate change adaptation (CCA)	CCM + CCA	Climate change mitigation (CCM)	Climate change adaptation (CCA)
1	Amount and proportion of taxonomy-eligible but not taxonomy-aligned economic activity referred to in Section 4.26 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI							Amount % Amount % Amount % Amount % Amount % Amount % Amount % Amount % Amount %
2	Amount and proportion of taxonomy-eligible but not taxonomy-aligned economic activity referred to in Section 4.27 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
3	Amount and proportion of taxonomy-eligible but not taxonomy-aligned economic activity referred to in Section 4.28 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
4	Amount and proportion of taxonomy-eligible but not taxonomy-aligned economic activity referred to in Section 4.29 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
5	Amount and proportion of taxonomy-eligible but not taxonomy-aligned economic activity referred to in Section 4.30 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI	2,105	40.9%	2,105	40.9%0		0%101	27.2%101 27.2%0		0%46 12.5%46	12.5%0	0%
6	Amount and proportion of taxonomy-eligible but not taxonomy-aligned economic activity referred to in Section 4.31 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
7	Amount and proportion of other taxonomy eligible but not taxonomy-aligned economic activities not referred to in rows 1 to 6 above in the denominator of the applicable KPI	3,042	59.1%3,042		59.1%0		0%270 72.8%270	72.8%0		0%322 87.5%322	87.5%0	0%
8	Total amount and proportion of taxonomy eligible but not taxonomy-aligned economic activities in the denominator of the applicable KPI	5,147		100%5,147	100%0		0%371	100%371 100%0		0%368 100%368	100%0	0%

Template 5: Taxonomy non-eligible economic activities,2023 € million, except where indicated

			Turnover		Capex		Opex
Row	Economic activities	Amount	%	Amount	%	Amount	%
1	Amount and proportion of economic activity referred to in row 1 of Template 1 that is taxonomy non-eligible in accordance with Section 4.26 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
2	Amount and proportion of economic activity referred to in row 2 of Template 1 that is taxonomy non-eligible in accordance with Section 4.27 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
3	Amount and proportion of economic activity referred to in row 3 of Template 1 that is taxonomy non-eligible in accordance with Section 4.28 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
4	Amount and proportion of economic activity referred to in row 4 of Template 1 that is taxonomy non-eligible in accordance with Section 4.29 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
5	Amount and proportion of economic activity referred to in row 5 of Template 1 that is taxonomy non-eligible in accordance with Section 4.30 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI	0	0%	0	0%	0	0%
6	Amount and proportion of economic activity referred to in row 6 of Template 1 that is taxonomy non-eligible in accordance with Section 4.31 of Annexes I and II to Delegated Regulation 2021/2139 in the denominator of the applicable KPI
7	Amount and proportion of other taxonomy non-eligible economic activities not referred to in rows 1 to 6 above in the denominator of the applicable KPI	87,451	100%	11,282	100%	3,421	100%
8	Total amount and proportion of taxonomy non-eligible economic activities in the denominator of the applicable KPI	87,451	100%	11,282	100%	3,421	100%