tm215953-3_20f - none - 177.7977221s

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

☑

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020

☐

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

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 American Depositary Shares	E	New York Stock Exchange* New York Stock Exchange
(Which represent the right to receive two Shares)	* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

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

None

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

None

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

Ordinary shares 3,605,594,848

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

Yes ☑ No ☐

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

Yes ☐ No ☑

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

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

Yes ☑ No ☐

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

Yes ☑ No ☐

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

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

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment on 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 issues its audit report. ☑

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

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

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

Item 17 ☐ Item 18 ☐

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

Yes ☐ No ☑

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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 forward-looking 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”), “Gas & Power” (or “G&P”), “Global Gas & LNG Portfolio” (or “GGP”), “Refining & Marketing and Chemicals” (or “R&M & C”), “Eni gas e luce, Power & Renewables” 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 Eni gas e luce or retail gas and power are to Eni's retail gas and power activities which are managed through its fully-owned subsidiary Eni gas e luce SpA and Eni gas e luce's controlled entities. The results of the operations of Eni gas e luce are included in the segment information “Eni gas e luce, Power & Renewables” for financial reporting purposes.

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.

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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
	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
	2nd and 3rd generation feedstock			Are feedstocks not in competition with the food supply chain as opposed to first generation feedstocks (vegetable oils). Second generation feedstocks are mostly agricultural non-food and Agro/Urban waste (such as animal fats, used cooking oils and agricultural waste) and the third generation feedstocks are Non-agricultural High Innovation Feedstocks (deriving from algae or waste).
	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 viii).
	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.

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	Condensates			Condensates is 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 CO2 eq.) of the main industrial activities operated by Eni divided by the productions (converted by homogeneity into barrels of oil equivalent using Eni’s average conversion factors) of the single businesses of reference.
	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.

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	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.
	Mineral Storage			According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
	Modulation Storage			According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings in demand.
	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 for on an equity basis, net of offset.
	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.
	Net Carbon Intensity			Ratio between the Net GHG lifecycle emissions and the energy 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.
	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.

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	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 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.
	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.

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	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 material balances and refineries' product yields.
	Ship-or-pay			Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
	Take-or-pay			Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
	Title Transfer Facility			The Title Transfer Facility, more commonly known as TTF, is a virtual trading point for natural gas in the Netherlands. TTF Price is quoted in euro per megawatt hour and, for business day, is quoted day-ahead, i.e. delivered next working day after assessment.
	UN SDGs			The Sustainable Development Goals (SDGs) are the blueprint to achieve a better and more sustainable future for all by 2030. Adopted by all United Nations Member States in 2015, they address the global challenges the world is facing, including those related to poverty, inequality, climate change, environmental degradation, peace and justice. For further detail see the website https://unsdg.un.org
	Upstream/Downstream			The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.
	Upstream GHG Emission intensity			Ratio between 100% Scope 1 GHG emissions from Upstream operated assets and 100% gross operated production (expressed in barrel of oil equivalent).

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ABBREVIATIONS

	mmCF			= million cubic feet
	BCF			= billion cubic feet
	mmCM			= million cubic meters
	BCM			= billion cubic meters
	BOE			= barrel of oil equivalent
	KBOE			= thousand barrel of oil equivalent
	mmBOE			= million barrel of oil equivalent
	BBOE			= billion barrel of oil equivalent
	BBL			= barrels
	KBBL			= thousand barrels
	mmBBL			= million barrels
	BBBL			= billion barrels
	mmBTU			= million British thermal unit
	ktonnes			= thousand tonnes
	KW			= kilowatt
	GW			= gigawatt
	Gcal			= giga calorie
	REDD+			= Reducing Emissions from Deforestation and Forest Degradation

	mmtonnes			= million tonnes
	MW			= megawatt
	GWh			= gigawatthour
	TWh			= terawatthour
	/d			= per day
	/y			= per year
	E&P			= the Exploration & Production segment
	G&P			= the Gas & Power business
	R&M & C			= the Refining & Marketing and Chemicals segment
	GGP			= the Global Gas & LNG Portfolio segment

CONVERSION TABLE

1 acre	= 0.405 hectares
1 barrel	= 42 U.S. gallons
1 BOE	= 1 barrel of crude oil	= 5,310 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 0.00665 barrels of oil equivalent
1 kilometer	= approximately 0.62 miles
1 short ton	= 0.907 tonnes	= 2,000 pounds
1 long ton	= 1.016 tonnes	= 2,240 pounds
1 tonne	= 1 metric ton	= 1,000 kilograms
		= approximately 2,205 pounds
1 tonne of crude oil	= 1 metric ton of crude oil	= approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees)

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Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB). The tables below present Eni’s selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2016, 2017, 2018, 2019 and 2020.

Following a reorganization of the Company to align with its strategy and long-term goals, management has changed the Group’s segment information for financial reporting purposes. See “Item 5 – Operating and Financial Review and Prospects”.

	Year ended December 31,
	2020		2019		2018		2017		2016
	(€ million except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA
Sales from continuing operations		43,987		69,881		75,822		66,919		55,762
Operating profit (loss) by segment from continuing operations
Exploration & Production		(610)		7,417		10,214		7,651		2,567
Gas & Power								75		(391)
Global Gas & LNG Portfolio		(332)		431		387
Refining & Marketing and Chemicals		(2,463)		(682)		(501)		981		723
Eni gas e luce, Power & Renewables		660		74		340
Corporate and Other activities		(563)		(688)		(668)		(668)		(681)
Unrealized intragroup profit elimination		33		(120)		211		(27)		(61)
Operating profit (loss) from continuing operations		(3,275)		6,432		9,983		8,012		2,157
Net profit (loss) attributable to Eni from continuing operations		(8,635)		148		4,126		3,374		(1,051)
Net profit (loss) attributable to Eni from discontinued operations										(413)
Net profit (loss) attributable to Eni		(8,635)		148		4,126		3,374		(1,464)
Data per ordinary share (euro)(1)
Net profit (loss) attributable to Eni basic and diluted from continuing operations		(2.42)		0.04		1.15		0.94		(0.29)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		0.00		0.00		0.00		0.00		(0.12)
Net profit (loss) attributable to Eni basic and diluted		(2.42)		0.04		1.15		0.94		(0.41)
Data per ADR ($)(1)(2)
Net profit (loss) attributable to Eni basic and diluted from continuing operations		(5.53)		0.09		2.72		2.12		(0.65)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		0.00		0.00		0.00		0.00		(0.25)
Net profit (loss) attributable to Eni basic and diluted		(5.53)		0.09		2.72		2.12		(0.90)

(1)

Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2020 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 12, 2021.

(2)

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	As of December 31,
	2020		2019		2018		2017		2016
	(€ million except data per share and per ADR)
CONSOLIDATED BALANCE SHEET DATA
Total assets		109,648		123,440		118,373		114,928		124,545
Finance debt (short-term and long-term debt) and lease liabilities		31,704		30,166		25,865		24,707		27,239
Capital stock issued		4,005		4,005		4,005		4,005		4,005
Non-controlling interest		78		61		57		49		49
Shareholders’ equity – Eni share		37,415		47,839		51,016		48,030		53,037
Capital expenditures from continuing operations		4,644		8,376		9,119		8,681		9,180
Weighted average number of ordinary shares outstanding (fully diluted – shares million)		3,573		3,592		3,601		3,601		3,601
Dividend per share (euro)(1)		0.36		0.86		0.83		0.80		0.80
Dividend per ADR ($)(1)(2)		0.82		1.93		1.96		1.81		1.77

(1)

(2)

Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented. Dividends per ADR for the years 2016 through 2019 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively. The dividend for 2020 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (€0.24 per ADR) at the Noon Buying Rate recorded on the payment date on September 23, 2020, while the balance of €0.48 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2020. The balance dividend for 2020 once the full-year dividend is approved by the Annual General Shareholders’Meeting is payable on May 26, 2021 to holders of Eni shares, being the ex-dividend date May 24, 2021.

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Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2016, 2017, 2018, 2019 and 2020. In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. Effective January 1, 2020, Eni has updated the conversion rate of gas produced to 5,310 cubic feet of gas equals 1 barrel of oil (it was 5,408 cubic feet of gas per barrel in previous reporting periods). The effect of this update on production expressed in BOE was 14 kBOE/d for the full year 2020 and the change in the initial reserves balance as of January 1, 2020 amounted to 67 mmBOE. Prior-year converted amounts were left unchanged. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depreciation and depletion charges. Other oil companies may use different conversion rates.

	Year ended December 31,
	2020		2019		2018		2017		2016
Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)		3,055		3,124		3,183		3,262		3,230
of which developed		2,218		2,219		2,208		2,220		2,190
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)		460		477		357		160		168
of which developed		233		269		205		43		43
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF)		15,554		17,111		17,324		17,290		18,462
of which developed		10,851		12,070		11,203		9,535		9,244
Proved reserves of natural gas of equity-accounted entities at period end (BCF)		2,447		2,721		2,400		2,182		3,871
of which developed		2,158		2,347		2,063		1,916		1,905
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end		5,984		6,287		6,356		6,430		6,613
of which developed		4,261		4,450		4,261		3,967		3,884
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end		921		981		797		560		877
of which developed		639		704		583		394		391
Average daily production of liquids (KBBL/d)(1)		841		890		884		852		878
Average daily production of natural gas available for sale (mmCF/d)(1)		4,077		4,576		4,630		4,734		4,329
Average daily production of hydrocarbons available for sale (KBOE/d)(1)		1,609		1,736		1,732		1,719		1,671
Hydrocarbon production sold (mmBOE)		575.2		630.6		625.0		622.3		608.6
Oil and gas production costs per BOE(2)		6.31		6.05		6.50		6.33		5.90
Profit per barrel of oil equivalent(3)		(4.33)		5.06		9.27		8.72		1.98

(1)

Referred to Eni’s subsidiaries and its equity-accounted entities. It excludes production volumes of hydrocarbon consumed in operation (124, 124, 119, 97, and 88 KBOE/d in 2020, 2019, 2018, 2017, and 2016 respectively).

(2)

Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements”. Oil and gas production costs per BOE exclude transportation costs relating to the export of the saleable volumes of oil and gas produced, other than the costs incurred to deliver hydrocarbons to a main pipeline, a common carrier, a refinery or a maritime terminal, when unusual physical or operational circumstances exist.

(3)

Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements” for a calculation of results of operations from oil and gas producing activities.

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RISK FACTORS

Strategic risks and risks related to the business activities and industries of Eni and its consolidated subsidiaries (together, the “Group”)

The Company’s performance is affected by volatile prices of crude oil and produced natural gas and by fluctuating margins on the marketing of natural gas and on the integrated production and marketing of refined products and chemical products

The price of crude oil is the single, largest variable that affects the Company’s operating performance and cash flow. The price of crude oil has a history of volatility because, like other commodities, it is cyclical and is influenced by several macro-factors that are beyond management’s control. Crude oil prices are mainly driven by the balance between global oil supplies and demand and hence the global levels of inventories and spare capacity. In the short-term, worldwide demand for crude oil is highly correlated to the macroeconomic cycle. A downturn in economic activity normally triggers lower global demand for crude oil and possibly a supply build-up. 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 in China, India, the United States and other large oil-consuming countries, financial crisis, geo-political crisis, local conflicts and wars, social instability, pandemic diseases, the flows of international commerce, trade disputes and governments’ fiscal policies, among others. All these events could influence demands for crude oil. In the long-term, factors which can influence demands for crude oil include on the positive side demographic growth, improving living standards and GDP expansion. Negative factors that may affect demand in the long-term comprise availability of alternative sources of energy (e.g., nuclear and renewables), technological advances affecting energy efficiency, measures which have been adopted or planned by governments all around the world to tackle climate change and to curb carbon-dioxide emissions (CO2 emissions), including stricter regulations and control on production and consumption of crude oil, or a shift in consumer preferences. The civil society and several governments all over the world, with the EU leading the way, have announced plans to transition towards a low-carbon model through various means and strategies, particularly by supporting development of renewable energies and the replacement of internal combustion vehicles with electric vehicles, including the possible adoption of tougher regulations on the use of hydrocarbons such as the taxation of CO2 emissions as a mitigation action of the climate change risk. The push to reduce worldwide greenhouse gas emissions and an ongoing energy transition towards a low carbon economy, which are widely considered to be irreversible trends, will represent in our view major trends in shaping global demand for crude oil over the long-term and may lead to structural lower crude oil demands and consumption. We also believe that the dramatic events of 2020 in relation to the spread of the COVID-19 pandemic could have possibly accelerated those trends. See the section dedicated to the discussion of climate-related risks below.

Global production of crude oil is controlled to a large degree by the OPEC cartel, which has recently extended to include other important oil producers like Russia and Kazakhstan (so-called OPEC+). 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. Also, sanctions imposed by the United States and the EU against certain producing countries may influence trends in crude oil prices. However, we believe that the continued rise of crude oil production in the United States due to the technology-driven shale oil revolution has somewhat reduced the ability of the OPEC+ to control the global supply of oil. To a lesser extent, factors like adverse weather conditions such as, hurricanes in sensitive areas like the Gulf of Mexico, and operational issues at key petroleum infrastructure can influence crude oil prices.

The year 2020 was one of the worst on record for the oil&gas industry due to the far-reaching consequences of the COVID-19 pandemic, the long-term impacts of which have yet to be understood and estimated. Almost all of the companies in the sector suffered material economic losses and cash flow shortfalls and saw their business fundamentals along with share prices significantly deteriorate due to a massive hit to global demand for crude oil and other energy products and to collapsing commodity prices as direct consequences of the lockdown measures imposed in the first months of the year by governments throughout the world to contain the spread of the pandemic, leading to the suppression of industrial activity, international commerce and travel as well as souring the moods of consumers. To make things worse, while demand was falling precipitously, in March 2020 the OPEC+ failed to reach a deal for

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production cuts claimed by some members to counteract the effects of the COVID-19 pandemic and Saudi Arabia decided to increase its output and reduce prices to gain market share. The concurrence of a material reduction in global crude oil demand and rising production on the part of the OPEC+ members triggered a collapse in crude oil prices. At the peak of the COVID-19 crisis and the price war, the value of the Brent crude benchmark had fallen to below 15 $/BBL, marking the lowest point over several decades on an inflation-adjusted basis. The situation of extreme oversupply in the month of April 2020 was signalled by ballooning global inventories, depletion of storage capacity and a strong contango structure in the prices of contracts for future deliveries. Subsequently, with the gradual easing of lockdown measures and the implementation from May 2020 of major output cuts by the members of the OPEC+ as well as major capex curtailments implemented by international oil&gas companies, Brent prices staged a significant comeback, recovering to a level of almost 45 $/BBL in July. However, this recovery weakened at the end of the summer and in the autumn months due to a continuing rise in COVID-19 cases in western countries, particularly in the United States, continental Europe and the UK forcing national or local governments to re-impose new restrictive measures or full lockdowns to curb the spread of the virus, which negatively affected the pace of economic recovery and the consumption of fuels like gasoline and gasoil. On the other hand, an acceleration in the economic recovery in mainland China and other Asian countries where the virus was more effectively contained helped sustain the price of crude oil and a reduction in global inventories. Finally, the recovery of crude oil prices gained strength in the final months of 2020 and in the first months of 2021 due to a favourable combination of market and macro developments, most notably: a break-through in the development and approval of effective vaccines against COVID-19, further acceleration in the pace of economic activity in Asia, the outcome of the presidential election in the United States which fuelled expectations of large stimulus measures in favour of the U.S. economy, the continuing commitments on the part of OPEC+ to support the rebalancing of the oil market by slowing down the planned curtailments of the extra production quotas enacted in May 2020 and finally the surprising announcement by Saudi Arabia that it would implement a voluntary cut of its production quota of 1 million barrels/day in the months of February and March 2021 to compensate for any possible impact on demand due to recrudescence of the pandemic in western countries. Unexpectedly, while oil companies’ executives, traders and fund managers were weighing all these macro and market developments, a massive, unprecedented cold snap hit the Northern-Eastern hemisphere, particularly Japan, South Korea and China, causing a spike in demand for oil-based heating fuels and LNG, which significantly boosted the market prices of all hydrocarbons. Due to such recent developments, Brent crude oil prices strengthened to 50 $/bbl at the end of 2020 and then rallied further in the first quarter of 2021 averaging about 60 $/bbl. Despite this improvement, we expect the trading environment for crude oil price to remain volatile and uncertain in 2021 due to the virus overhang, a weak macroeconomic backdrop in the United States and Europe and high inventory levels in OECD countries, which remain above historical averages.

The COVID-19 pandemic negatively and materially affected a weak global natural gas market. As a result of the gas demand collapse recorded in the first half of 2020 due to the economic crisis resulting from COVID-19, gas prices fell to unprecedented lows in all the main geographies. Likewise, crude oil and natural gas prices recovered in the second half of the year supported by an improving economy and falling production levels due to capex constraints on global oil&gas companies. Overall, natural gas prices fell remarkably in 2020 (the prices at the Italian spot market were 35% lower than in 2019). However, at the end of 2020 and in January 2021 natural gas prices staged a material comeback supported by record seasonal demand in the Northern-Eastern hemisphere driven by record low temperatures.

Lower hydrocarbon prices from one year to another negatively affect the Group’s consolidated results of operations and cash flow. 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 2020, the Brent price averaged about 42 $/bbl, a decrease of 35% compared to 2019, which significantly and adversely affected Eni’s results of operations and cash flow for the year. We estimated that lower equity crude oil realizations and other scenario effects (lower equity gas prices, lower refining margins and other declines as described below) reduced the Company’s underlying operating profit and the net cash provided by operating activities by about €7 billion.

Considering the risks and uncertainties to the outlook for 2021, we are retaining a prudent financial framework and capital discipline in our investment decisions, while we are assuming a Brent price forecast of 50 $/bbl for the full year. Based on the current oil&gas assets portfolio of Eni, management estimates that the Company’s cash flow from operations will vary by approximately €150 million for each one-dollar change in the price of the Brent crude oil benchmark compared to the 50 $/bbl scenario adopted by management for the current year and for proportional changes in gas prices.

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In addition to the short-term impacts on the Group’s profitability, a market crisis like the one experienced in 2020 may also alter the fundamentals of the oil and natural gas markets. Lower oil and gas prices over prolonged periods of time may have material adverse effects on Eni’s performance and business outlook, because such a scenario may limit the Group’s ability to finance expansion projects, further reducing the Company’s ability to grow future production and revenues, and to meet contractual obligations. The Company may also need to review investment decisions and the viability of development projects and capex plans and, as a result of this review, the Company could reschedule, postpone or curtail development projects. A structural decline in hydrocarbon prices could trigger a review of the carrying amounts of oil and gas properties and this could result in recording material asset impairments and in the de-booking of proved reserves, if they become uneconomic in this type of environment.

In the course of 2020 Eni’s management revised its view of the oil market fundamentals to factor in certain emerging trends. Management considered that the lockdown measures in response to COVID-19 could result in a prolonged period of weak oil demand. Furthermore, the massive actions in support of the economic recovery planned by governments in several countries may have a strong environmental footprint and be supportive of the green economy, leading to a potential acceleration in the pace of energy transition and in the replacement of hydrocarbons in the energy mix in the long-term. Based on these considerations, in 2020 the Company revised its long-term forecast for hydrocarbon prices, which are the main driver of capital allocations decisions and of the recoverability assessment of the book values of our non-current assets. The revised scenario adopted by Eni foresees a long-term price of the marker Brent of 60 $/bbl in 2023 real terms compared to the previous assumption of 70 $/bbl. The price of natural gas at the Italian spot market “PSV” is estimated at 5.5 $/mmBTU in real terms in 2023 as compared to the previous assumption of 7.8 $/mmBTU. This changed outlook for hydrocarbons prices drove the recognition of significant impairment losses relating to oil&gas assets (€1.9 billion, pre-tax). For further details, see the notes to the consolidated financial statements. Furthermore, given the decline in crude oil prices used in the estimation of proved reserves according to the SEC rules compared to 2019 (average of the first-of-the-day price of each month at 41 $/bbl in 2020 vs. 63 $/bbl in 2019), we were forced to debook 124 mmBOE of reserves that have become uneconomic in this environment.

Finally, during a downturn like the one experienced in 2020, the Group’s access to capital may be reduced and lead to a downgrade or other negative rating action with respect to the Group’s credit rating by rating agencies. These downgrades may negatively affect the Group’s cost of capital, increase the Group’s financial expenses, and may limit the Group’s ability to access capital markets and execute aspects of the Group’s business plans.

Eni estimates that approximately 50% of its current production is exposed to fluctuations in hydrocarbons prices. Exposure to this strategic risk is not subject to economic hedging, except for some specific market conditions or transactions. The remaining portion of Eni’s current production is largely unaffected by crude oil price movements considering that the Company’s property portfolio is characterized by a sizeable presence of production sharing contracts, whereby 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 hence production, and vice versa.

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.

Margins on the manufacturing and sale of fuels and other refined products, chemical commodities, and other energy commodities are driven by economic growth, global and regional dynamics in supplies and demand and other competitive factors. Generally speaking, the prices of products mirror that of oil-based feedstock, but they can also move independently. Margins for refined and chemical products depend upon the speed at which products’ prices adjust to reflect movements in oil prices. Margins at our business of wholesale marketing of natural gas are driven by the spreads between spot prices at continental hubs to which our procurement costs are indexed and the spot prices at the Italian hub where a large part of our gas sales occur. These spreads can be very volatile.

In 2020, demand and margins for fuels and petrochemical products were materially hit by the economic downturn triggered by the COVID-19 pandemic, resulting in lower demand for fuels and petrochemical commodities. The trading environment was particularly unfavourable in the refining business due to an unprecedented combination of negative market trends. During the peak of the pandemic crisis in

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the second quarter of 2020, the lockdown measures imposed by governments throughout the world to curb the spread of the pandemic resulted in the suppression of air travel and people’s commuting by car leading to a massive decline in worldwide consumption of gasoline, kerosene and other fuels. Furthermore, while those restrictive measures were eased in Asia and other parts of the world, they have continued or have been re-imposed in Italy and other European countries, which are the main reference markets of our refining and marketing business. Although since the implementation of the production cuts by OPEC+ producers, crude oil prices have been moderately recovering throughout 2020, the increases in the cost of the feedstock did not translate into higher prices of fuels due to a depressed demand environment. Finally, the profitability of our business was also negatively affected by the appreciation of sour crude oils towards medium/light qualities such as the Brent, due to market dislocations and the effects of the production cuts implemented by the OPEC+, which reduced availability of sour crudes in the marketplace. This latter trend negatively affected the profitability of conversion plants, which are normally supported by the fact that heavy and sour crudes trade at a discount vs. the light qualities as the Brent. Due to all those market trends, the Company’s own internal performance measure to gauge the profitability of its refineries, the SERM (see glossary), fell to historic lows over the second half of 2020, plunging into negative territory at the end of 2020 and the beginning of 2021 in concomitance with the rally in crude oil prices, which has yet to be supported by a recovery of fuel demand in Europe. This trend will negatively affect the profitability of our refining business in 2021. The sales volumes at our network of service stations were significantly impacted by lower consumption due to the lockdown and anti-pandemic measures. The deteriorated outlook for refining margins and fuels consumption triggered a revision of the book value of the Company’s oil-based refining assets leading to the recognition of €1.2 billion of impairment losses.

The chemical business of Eni was negatively affected by a significant reduction in demand in the segments most exposed to the COVID-19 crisis such as elastomers following the contraction in the automotive sector, while the polyethylene margins were supported both by the reduction in the cost of oil feedstock and by strong demand for single-use plastics and packaging as consequence of higher demand for goods related to “stay-at-home economy”.

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 characterised 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. The economic crisis caused by the suppression of industrial activity and travel in response to the COVID-19 pandemic materially and negatively impacted demand for the Company’s products, driving a strong increase in the level of competition across all sectors where we are operating. We believe that the pandemic will have enduring effects on the competition within the oil&gas sectors, including the refining and marketing of fuels and other energy commodities and the supply of energy products to the retail segment.

Exploration & Production

•

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 maximise hydrocarbon recovery. Because of its smaller size relative to 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. 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. The COVID-19 pandemic has caused exploration&production companies to significantly reduce their capital investment in response to lower cash flows from operations and to focus on the more profitable and scenario-resilient projects. We believe that this development will be long-lasting and likely drive increased competition among players to gain access to relatively cheaper reserves (onshore vs. offshore; proven areas vs. unexplored areas).

Global Gas & LNG Portfolio

•

In the Global Gas & LNG Portfolio business, Eni is facing strong competition in the European

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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 our wholesale gas business are subject to global and regional dynamics of gas demand and supplies. 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. In 2020, the economic crisis triggered by the COVID-19 pandemic exacerbated the already weak fundamentals of the gas market. In fact, the lockdown of European economies resulted in sharply lower gas consumption leading to intensified competitive pressures. These developments caused lower sales volumes of gas marketed via pipeline and by our LNG business and significantly lower prices. In 2020 Eni’s gas and LNG sales declined by 11% due to the impact of the economic crisis triggered by the pandemic. Sales margins at our LNG business were put under pressure by collapsing demand due to the lockdown of Asian economies, which are the main outlet of global LNG production, as many buyers requested activation of the force majeure clauses for not lifting LNG contracted volumes. These developments led to increased competition in the global LNG market, dragging down sales margins. We expect continued competitive pressure in our wholesale gas and LNG businesses. However, in the first months of 2021 a colder-than normal winter in the Northern Hemisphere has supported the price of gas and LNG.

Refining & Marketing

•

In the Refining & Marketing segment, Eni is facing competition both in the refining business and in the retail marketing activity. Our Refining business has been negatively affected for years by structural headwinds due to muted trends in the European demand for fuels, refining overcapacity 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. This unfavourable competitive environment has been exacerbated by the effects of the 2020 economic crisis due to the COVID-19 pandemic, the consequent lockdown of entire economies and travel restrictions, which drove a collapse in the consumption of motor gasoline, jet fuels and other refined products. In the initial stages of the global energy downturn, refining margins were supported by a collapse in crude oil prices. Subsequently, as crude oil prices found support in the production curtailments implemented by the OPEC+, refining margins were severely hit by the weakness in global demand for fuels due to low propensity of people for travelling, which squeezed relative prices of fuels vs. the oil feedstock cost. This trend became particularly unfavourable starting from the summer months when refining margins were much less profitable, until the last months of the year when they even recorded negative value. On average, in 2020, the refining margin (SERM) dropped materially, down by 60% as compared to the prior year. Furthermore, Eni’s refining profitability was exposed to the volatility in the spreads between crudes with high sulphur content or sour crudes and the Brent crude benchmark, which is a low-content sulphur crude. Eni’s complex refineries are able to process sour crudes, which typically trade at a discount over Brent crude. Historically, this discount has supported the profitability of complex refineries, like our plant at Sannazzaro in Italy. However, in the course of 2020, a shortfall in supplies of sour crudes due to the production cuts implemented by OPEC+ in response to the COVID-19 pandemic, drove an appreciation of the relative prices of sour crudes as compared to Brent, which negatively affected the results of Eni’s refining business by reducing the advantage of processing sour crudes. Eni believes that the competitive environment of the refining sector will remain challenging in the foreseeable future, considering ongoing uncertainties and risks relating to the strength of the economic recovery in Europe and worldwide, and risks of another round of lockdown measures in case of failure by governments to effectively contain the spread of the pandemic, which would weigh heavily on demand for fuels. Other risks factors include refining overcapacity in the European area and expectations of a new investment cycle driven by capacity expansion plans announced in Asia and the Middle East, potentially leading to global oversupplies of refinery products. Due to a reduced profitability outlook in the refining business, management recognized impairment charges of €1.2 billion to align the book value of refineries to their realizable values.

The business of marketing refined products to drivers at our network of service stations and to large account customers (airlines, public administrations, transport and industrial customers, bulk buyers and resellers) is facing competition from other oil companies and newcomers such as low-scale and local operators, and un-branded networks with light cost structure. All of these operators compete with each other primarily in terms of pricing and, to a lesser extent, service

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quality. Against this backdrop, in 2020 the lockdown measures adopted to contain the spread of the pandemic resulted in the suppression of travel and road transportation which weighed heavily on throughput volumes at our network of service stations in Italy and other European markets which were down by 19.9% as compared to the prior year.

Chemicals

•

Eni’s Chemical business is in a highly-cyclical, very competitive sector. We have been facing for years strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditised market segments such as the production of basic petrochemical products (like ethylene and polyethylene), where 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 and proximity to end-markets. Excess worldwide capacity of petrochemical commodities has also fuelled competition in this business. Furthermore, 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 for the production of ethylene than the oil-based feedstock utilised by Eni’s petrochemical subsidiaries. Finally, rising public concern about climate change and the preservation of the environment has begun to negatively affect the consumption of single-use plastics. In 2020, these competitive dynamics were greatly amplified by the economic crisis triggered by the lockdown measures in response to the COVID-19 pandemic, which negatively affected plant utilization rates and sales volumes, particularly in those segments more exposed to the recession of their customer segments, like in the case of sales volumes of elastomers to the automotive industry. However, other chemicals segments performed relatively well, because the “stay-at-home economy” boosted demands for certain products like polyethylene, that is utilized in the packaging of food and other consumer goods as well as in materials for the sanitary emergency. These trends supported polyethylene margins. Looking forward, management believes that the competitive environment in the Chemicals businesses will remain challenging due to uncertainties and risks relating to the strength of the economic recovery or another round of lockdown measures in case of by governments to effectively contain the spread of the pandemic.

Retail gas and power

•

Eni’s retail gas and power business engages in the supply of gas and electricity to customers in the retail markets mainly in Italy, France and other countries in Europe. Customers include households, large residential accounts (hospitals, schools, public administration buildings, offices) and small and medium-sized businesses. The retail market is characterised 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. In this segment, competition has intensified in recent years due to the progressive liberalisation of the market and the ability of residential customers to switch smoothly from one supplier to another. In 2020, the performance of this business was negatively affected by the economic crisis caused by the lockdown measures imposed to contain the spread of COVID-19, which reduced energy demand particularly in the segments of medium and small businesses, increased credit risk and triggered increased credit losses. In 2020, sales volumes of natural gas to the retail market fell by 11%; however, this trend was partly offset by greater power requirements due to the “stay-at-home economy” with sales volumes up by 13% for the year. We anticipate that competition will remain strong in this business due to the likelihood of a slow economic recovery and weak trends in energy consumption, as well as the potential risk of yet another downturn in case of new lockdown measures to contain the pandemic and rising sensitivity among households and businesses to reduce the cost of the energy bill.

Eni also engages in the business of producing gas-fired electricity that is largely sold at wholesale energy market and balancing market (so called MSD) in Italy. Margins on the sale of electricity have declined in recent years due to oversupplies, weak economic growth and inter-fuel competition. The pandemic-driven economic crisis has exacerbated those trends, causing a material reduction in power consumption due to the lockdowns of entire industrial sectors and producing activities. In 2020, power sales in the wholesale market in Italy fell by 10% due to lower consumption by Italian businesses. Management believes that these factors will continue to negatively affect clean spark spread margins on electricity in the Italian wholesale markets.

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In case the Company is unable to effectively manage the above described competitive risks, which may increase in case of a weaker-than-anticipated recovery in the post-pandemic economy or in a worst case scenario of the imposition by governments of new lockdown measures and other restrictions in response to the pandemic, the Group’s 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.

Safety, security, environmental and other operational risks

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 adverse weather events can trigger damaging consequences such as explosions, blow-outs, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants and pollutants in the air, the ground and in the 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 and liquidity depend on its ability to identify and address the risks and hazards inherent to operating in those industries.

In the Exploration & Production segment, Eni faces natural hazards and other operational risks including those relating to the physical and geological characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni’s personnel and risks of blowout, fire or explosion.

Eni’s activities in the Refining & Marketing and Chemical segment entail health, safety and environmental risks related to the handling, transformation and distribution of oil, oil products and certain petrochemical products. These risks can arise from the intrinsic characteristics and the overall lifecycle of the products manufactured and the raw materials used in the manufacturing process, such as oil-based feedstock, catalysts, additives and monomer feedstock. These risks comprise flammability, toxicity, long-term environmental impact such as greenhouse gas emissions and risks of various forms of pollution and contamination of the soil and the groundwater, emissions and discharges resulting from their use and from recycling or disposing of materials and wastes at the end of their useful life.

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.

Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2020, approximately 65% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Angola, Norway, Congo, Indonesia, the United Arab Emirates, Italy, Ghana, Venezuela, the United Kingdom, Nigeria and the United States. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. Offshore accidents and 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, 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.

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, 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. Eni seeks to manage these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines,

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storage sites and other facilities, and managing its operations in a safe and reliable manner and in compliance with all applicable rules and regulations, as well as by applying the best available techniques in the marketplace. 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 or other unexpected drivers could cause oil spills, blowouts, fire, release of toxic gas and pollutants into the atmosphere or the environment or in underground water and other incidents, all of which could lead to 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.

Eni’s operations are often conducted in difficult and/or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic. In such locations, the consequences of any incident could be greater than in other locations. Eni also faces risks once production is discontinued because Eni’s activities require the decommissioning of productive infrastructures and environmental sites remediation and clean-up. 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. 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 unfavourable events and in connection with environmental clean-up and remediation. As of the date of this filing, maximum compensation allowed under such insurance coverage is equal to $1.2 billion in case of offshore incident and $1.4 billion in case of incident at onshore facilities (refineries). Additionally, the Company may also activate further insurance coverage in case of specific capital projects and other industrial initiatives. 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, for example, 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 occurrence of any of the above mentioned risks could have a material and adverse impact 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 and could also damage the Group’s reputation.

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 our businesses engaged in the marketing of natural gas and, to a lesser extent, the Refining & Marketing 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. In 2020, our sales volumes of gas both at wholesale markets and at the retail sector particularly in Italy were negatively affected by lower seasonal sales in the first quarter.

Risks associated with the exploration and production of oil and natural gas

The exploration and production of oil and natural gas require high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil and gas fields. The exploration and production activities are subject to mining risk and the risks of cost overruns and delayed start-up at the projects to develop and produce hydrocarbons reserves. Those risks could have an adverse, significant impact on Eni’s future growth prospects, results of operations, cash flows, liquidity and shareholders’ returns.

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

Exploratory drilling efforts may be unsuccessful

Exploration activities are mainly subject to 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 prospect off West Africa, Indonesia, the Mediterranean Sea and the Caspian Sea). In these locations, the Company generally experiences higher operational risks and more challenging conditions and incurs higher exploration costs than onshore. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the operational and the financial risks associated with these activities. Because Eni plans to make significant investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas, which is highly dependent on the rate of success of exploration projects and could have an adverse impact on Eni’s future performance and returns.

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

Eni is executing or is planning to execute several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or in environmentally sensitive locations. Eni’s future results of operations and business prospects depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include:

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the outcome of negotiations with joint venture partners, governments and state-owned companies, suppliers and potential customers to define project terms and conditions, including, for example, Eni’s ability to negotiate favourable long-term contracts to market gas reserves;

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commercial arrangements and granting of all necessary administrative authorizations to build pipelines and related equipment to transport and market hydrocarbons;

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timely issuance of permits and licenses by government agencies;

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the ability to carry 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 equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; delays in achievement of critical phases and project milestones;

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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;

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performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) contractual scheme;

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changes in operating conditions and cost overruns;

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the actual performance of the reservoir and natural field decline; and

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the ability and time necessary to build suitable transport infrastructures to export production to final markets.

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The occurrence of any of such risks may negatively affect the time-to-market of the reserves and cause cost overruns and a delayed pay-back period, therefore adversely affecting the economic returns of Eni’s development projects and the achievement of production growth targets.

Development projects normally have long lead times due to the complexity of the activities and tasks that need to be performed before a project final investment decision is made and commercial production can be achieved. Those activities include the appraisal of a discovery to evaluate the technical and economic feasibility of the development project, obtaining the necessary authorizations from governments, state agencies or national oil companies, signing agreements with the first party regulating a project’s contractual terms such as the production sharing, obtaining partners’ approval, environmental permits and other conditions, signing long-term gas contracts, carrying out the concept design and the front-end engineering and building and commissioning the related plants and facilities. All these activities normally can take years to perform. As a consequence, rates of return for such projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from those estimated when the investment decision was made, thereby leading to lower return rates. 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. Furthermore, Eni may not have full operational control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operations and strategic objectives due to the nature of its relationships.

Finally, if the Company is unable to develop and operate major projects as planned, particularly if the Company fails to accomplish budgeted costs and time schedules, it could incur significant impairment losses of capitalised costs associated with reduced future cash flows of those projects.

Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition

In case the Company’s exploration efforts are unsuccessful at replacing produced oil and natural gas, its reserves will decline. In addition to being a function of production, revisions and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its production sharing agreements (“PSAs”), whereby 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. Based on the current portfolio of oil and gas assets, Eni’s management estimates that production entitlements vary on average by approximately 330 barrels/d for each $1 change in oil prices based on current Eni’s assumptions for oil prices. In 2020, production and year-end proved reserves benefitted from lower oil prices which translated into higher entitlements (approximately 12 kBOE/d of incremental production and 118 MBOE of reserves volumes). In case oil prices differ significantly from Eni’s own forecasts, the result of the above-mentioned sensitivity of production to oil price changes may be significantly different.

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 production growth and reserve replacement, Eni’s future total proved reserves and production will decline.

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 expenditures depends on a number of factors, assumptions and variables, including:

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

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

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

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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

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

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

The prices used in calculating Eni’s estimated proved reserves are, in accordance with the SEC requirements, calculated by determining the unweighted arithmetic average of the first day-of-the-month commodity prices for the preceding twelve months. For the 12-months ending at December 31, 2020, average prices were based on 41 $/BBL for the Brent crude oil, which was materially lower than the reference price of 63 $/BBL utilized in 2019 due to the effects of the pandemic-induced economic crisis on demand and prices of hydrocarbons. Also, the reference price of natural gas was markedly lower than in 2019. Those reductions resulted in Eni having to remove 124 MBOE of proved reserves because they have become uneconomical in this price environment.

Accordingly, the estimated reserves reported as of the end of 2020 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.

At the end of 2020 due to a combination of a slowdown in development expenditures because of the need to preserve the Group liquidity during the downturn and the removal of a significant amount of reserves that have become uneconomical in this environment, the Group reserves additions for the year of 271 MBOE fell significantly short of the volume produced of 634 MBOE, negatively affecting the replacement ratio of produced volumes and the total quantity of proved reserves at year-end compared to 2019 (down by 5%) which could negatively affect the Group’s growth prospects going forward.

The development of the Group’s proved undeveloped reserves 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

At December 31, 2020, approximately 30% of the Group’s total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves 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 not prove to be accurate and are subject to the risk of a structural decline in the prices of hydrocarbons due to possible long-lasting effects associated with the COVID-19 pandemic, including acceleration towards a low-carbon economy and a shift in consumers’ behaviour and preferences. In case of a continued decline in the prices of hydrocarbon the Group may not have enough financial resources to make the necessary expenditures to recover undeveloped reserves. The Group’s reserve report at December 31, 2020 includes estimates of total future development and decommissioning costs associated with the Group’s proved total reserves of approximately €27.7 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities). 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 or otherwise, it will be required to remove the associated volumes from the Group’s reported proved reserves.

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 many other commercial activities. Furthermore, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. As a result of these trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the

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Italian statutory tax rate for corporate profit, which currently stands at 24%. 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 the current uncertain financial and economic environment, governments are facing greater pressure on public finances, which may induce them to intervene in the fiscal framework for the oil and gas industry, including the risk of increased taxation, windfall taxes, and even nationalisations and expropriations.

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

The present value of future net revenues from Eni’s proved reserves may differ from the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with the SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month un-weighted 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 used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:

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

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the actual cost and timing of development and production expenditures;

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the timing and amount of actual production; and

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changes in governmental regulations or taxation.

The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. Additionally, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni’s reserves or the crude oil and natural gas industry in general. At December 31, 2020 the net present value of Eni’s proved reserves totalled approximately €27.7 billion and was materially lower than at the end of 2019 because the average prices used to estimate Eni’s proved reserves and the net present value at December 31, 2020, as calculated in accordance with the SEC rules, were 41 $/barrel for the Brent crude oil compared to 63 $/barrel utilized in 2019 due to the big fall recorded in hydrocarbons prices during the course of 2020 as a result of the demand contraction caused by the COVID-19 pandemic. Actual future prices may materially differ from those used in our year-end estimates.

Oil and gas activity may be subject to increasingly high levels of regulations throughout the world, which may impact our extraction activities and the recoverability of reserves

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, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. These risks can limit the Group’s access to hydrocarbons reserves or may cause the Group to redesign, curtail or cease its oil&gas operations with significant effects on the Group’s business prospects, results of operations and cash flow.

In Italy, the activities of hydrocarbon development and production are performed by oil companies in accordance to concessions granted by the Ministry of Economic Development in agreement with the relevant Region territorially involved in the case of onshore concessions. Concessions are granted for an initial twenty-year term; the concessionaire is entitled to a ten-year extension and then to one or more five-year extensions to fully recover a field’s reserves and investments on the condition that the concessionaire has fulfilled all obligations related to the work program agreed in the initial concession award. In case of delay in the award of an extension, the original concession remains fully effective until the administrative procedure to grant an extension is finalized. These general rules are to be coordinated with a new law that was enacted in February 2019. This law requires certain Italian administrative bodies to adopt by the end of 2021 a plan intended to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, a moratorium on exploration activities, including the award of new

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exploration leases, is in effect. Following the plan approval, exploration permits will resume in areas that have been identified as suitable and new exploration permits can be awarded. However, in unsuitable areas, exploration permits will be repealed, applications for obtaining new exploration permits ongoing at the time of the law enactment will be rejected and no new permit applications can be filed. As far as development and production concessions are concerned, pending the national plan approval, ongoing concessions remain in effect and administrative procedures underway to grant extensions to expired concessions remain unaffected; however, no applications to obtain new concessions can be filed. Once the above mentioned national plan is adopted, development and production concessions that fall in suitable areas can be granted further extensions and applications for new concessions can be filed; however, development and production concessions in place as at the approval of the national plan that fall in unsuitable areas will be repealed at their expiration, no further extensions will be granted, and no new concession applications can be filed or awarded. According to the statute, areas that are suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline.

The Group’s largest operated development concession in Italy is Val d’Agri, which term expired on October 26, 2019. Development activities at the concession have continued since then in accordance with the “prorogation regime” described above, within the limits of the work plan approved when the concession was first granted. The Company filed an application to obtain a ten-year extension of the concession in accordance to the terms set by the law and before the enactment of the new law on the national plan for hydrocarbons activity. In this application the Company confirmed the same work program as in the original concession award. Similarly, Company operations are underway in accordance to the ongoing prorogation regime at another 41 expired Italian concessions for hydrocarbons development and production. The Company has also filed requests for extensions within the terms of the law for those concessions.

As far as proven reserves estimates are concerned, management believes the criteria laid out in the new law to be high-level principles, which make it difficult to identify in a reliable and objective manner areas that might be suitable or unsuitable to hydrocarbons activities before the plan is adopted by Italian authorities. However, based on the review of all facts and circumstances and on the current knowledge of the matter, management does not expect any material impact on the Group’s future performance.

Eni’s future performance depends on its ability to identify and mitigate the above-mentioned risks and hazards which are inherent to its oil&gas business. Failure to properly manage those risks, the Company’s underperformance at exploration, development and reserve replacement activities or the occurrence of unforeseen regulatory 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 shares.

Risks related to political considerations

As of December 31, 2020, approximately 83% of Eni’s proved hydrocarbon reserves were located in non-OECD countries, mainly in Africa and central-south East Asia, 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:

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socio-political instability leading to internal conflicts, revolutions, establishment of non-democratic regimes, protests, attacks, strikes and other forms of civil disorder and unrest, such as strikes, riots, sabotage, 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;

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

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unfavourable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalisation or forced divestiture of assets and unilateral cancellation or modification of contractual terms;

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sovereign default or financial instability due to the fact that those countries rely heavily on petroleum revenues to sustain public finance and petroleum revenues have dramatically contracted in 2020 due plunging hydrocarbons prices as a consequence of the global economic crisis caused by the COVID-19 pandemic. 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;

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restrictions on exploration, production, imports and exports;

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tax or royalty increases (including retroactive claims);

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

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complex processes of granting authorisations or licences affecting time-to-market of certain development projects.

The financial outlook of several, non-OECD countries where Eni is operating was significantly affected by the material contraction recorded in hydrocarbons revenues following the COVID-19 pandemic, which also increased the counterparty risk of a few state-owned or privately-held local companies that are Eni’s partners in certain projects to develop oil&gas reserves.

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

Eni’s operations in Libya are currently exposed to significant geopolitical risks. The current situation of social and political instability dates back to the revolution of 2011 that brought a change of regime and a civil war, triggering an uninterrupted period of lack of well-established institutions and recurrent episodes of internal conflict, clashes, disorders and other forms of civil turmoil. In the year of the revolution, Eni’s operations in Libya were materially affected by a full-scale war, which forced the Company to shut down its development and extractive activities for almost all of 2011, with a significant negative impact on the Group’s results of operation and cash flow. In subsequent years Eni has experienced frequent disruptions to its operations, albeit on a smaller scale than in 2011, due to security threats to its installations and personnel. In April 2019, a resurgence of the socio-political instability and a failure by the opposed factions to establish a national government triggered the resumption of the civil war with armed clashes in the area of Tripoli and elsewhere in the country. The situation continued to escalate also because international negotiations aimed at restoring a state of peace and stability proved elusive. At the beginning of 2020 oil export terminals in the eastern and southern parts of Libya were blocked, halting most of the country’s oil export terminals, and force majeure was declared at several Libyan production facilities. Production shutdowns also involved certain of the Company’s profit centres (the El Feel oilfield and the Bu Attifel offshore platform). The Company repatriated its personnel and strengthened security measures at its plants and facilities still in operation. However, despite this difficult framework, the Company’s largest assets in Libya – the Bahr Essalam offshore platform and the onshore Mellitah oil and gas production centre – have continued to produce regularly. Due to those developments, we estimated a loss of output in the range of 9 KBBL/d on average for the year 2020. In late September, the situation began to improve thanks to a temporary agreement between the conflicting factions, the blockade was lifted at the main ports for exporting crude oil and production resumed at the main fields, revoking force majeure. Despite this, 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.

As of December 31, 2020, Libya represented approximately 10% of the Group’s total production; this percentage is forecasted to decrease in the medium term in line with the expected implementation of the Group’s strategy intended to diversify the Group’s geographical presence to better balance the geopolitical risk of the portfolio. In the event of major adverse events, such as the escalation of the internal conflict into a full-blown civil war, attacks, sabotage, social unrest, clashes and other forms of civil disorder, Eni could be forced to reduce or to shut down completely its production activities at its Libyan fields, which would significantly hit results of operations and cash flow.

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Venezuela is currently experiencing a situation of financial stress, which has been exacerbated by the economic recession caused by the effects of the COVID-19 pandemic. Lack of financial resources to support the development of the country’s hydrocarbons reserves has negatively affected the country’s production levels and hence fiscal revenues. The situation has been made worse by certain international sanctions targeting the country’s financial system and its ability to export crude oil to U.S. markets, which is the main outlet of Venezuelan production (see also “Sanctions targets” below).

Presently, the Company retains only one valuable asset in Venezuela: the 50%-participated Cardón IV joint venture, which is operating a natural gas offshore project and is supplying its production to the national oil company, PDVSA, under a long-term supply agreement. We also hold an equity interest in other two oil projects: the PetroJunin oilfield and the Corocoro field, with respect to which in past years we have registered significant impairment losses and reserves de-bookings, with currently little value left to recover. The main risk to Eni’s ability to recover its investment is the continued difficulty on the part of PDVSA to pay the receivables for the gas supplies of Cardón IV, resulting in a significant amount of overdue receivables. The joint-venture is systematically booking a loss provision on the revenues accrued. The expected credit loss was based on management’s appreciation of the counterparty risk driven by the findings of a review of the past experience of sovereign defaults on which basis a deferral in the collection of the gas revenues was estimated. As of December 31, 2020, Eni’s invested capital in Venezuela was approximately $1 billion. Despite the negative financial outlook of the country and of PDVSA, during the course of 2020 the Company was able to collect a certain percentage of accrued revenues, in line with management’s estimates of the expected credit losses. Eni expects the financial and political outlook of the country to remain a risk factor to Eni’s operations there for the foreseeable future.

We have significant credit exposure in Nigeria to state-owned and privately-held local companies, where the overall financial and economic outlook of the country has been made worse by the contraction of petroleum revenues due to the crisis of the oil sector in 2020 caused by the COVID-19 pandemic. Our credit exposure is due to the fact that we are funding the share of capital expenditures pertaining to Nigerian joint operators at Eni-operated oil projects. We have incurred in the past and it is possible to continue incurring in the future significant credit losses because of the ongoing difficulties of our Nigerian counterparts to reimburse amounts past due.

Eni is closely monitoring political, social and economic risks of the countries in which it has invested or intends to invest, in order to evaluate the economic and financial return of capital projects and to selectively evaluate projects. While the occurrence of these events is unpredictable, the occurrence of any such 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 shares.

Finally, the United Kingdom left the European Union at the end of January 2020. Due to this decision, it is possible that in the future we may experience delays in moving our products and employees between the UK and EU. Also, additional tariffs and taxes could impact the demand for some of our products and this, combined with the weak macroeconomic conditions in both the EU and UK due to the COVID-19 pandemic, could have a material adverse effect on energy demand.

Sanction targets

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

In response to the Russia-Ukraine crisis, the European Union and the United States have enacted sanctions targeting, inter alia, the financial and energy sectors in Russia by restricting the supply of certain oil and gas items and services to Russia and certain forms of financing. Eni has adapted its activities to the applicable sanctions and will further adapt its business to any subsequent restrictive measures that shall be adopted by the relevant authorities. In response to these restrictions, the Company has put on hold its projects in the upstream sectors in Russia and currently is not engaged in any oil & gas project in the country. It is not possible to rule out the possibility that wider sanctions targeting the Russian energy, banking and/or finance industries may be implemented. Further sanctions imposed on Russia, Russian citizens or Russian companies by the international community, such as restrictions on purchases of Russian gas by European companies or measures restricting dealings with Russian counterparties, could adversely impact Eni's business, results of operations and cash flow. Furthermore, an escalation of the international crisis, resulting in a tightening of sanctions, could entail a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group's business, financial conditions, results of operations and prospects.

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Starting from 2017, the United States 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 Petroleos de Venezuela SA (“PDVSA”), the main national state-owned enterprise, has been added to the “Specially Designated Nationals and Blocked Persons List” and the Venezuelan governments 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 has been further tightened in the final part of 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 could jeopardize our ability to collect the trade receivable owed to us for our activity in the country.

Eni is carefully evaluating on a case by case basis the adoption of measures adequate 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.

Risks specific to the Company’s gas business in Italy

Current, negative trends in gas demands and supplies in Europe 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, pre-set 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 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. A reduction of the spreads between Italian and European spot prices for gas could negatively affect the profitability of our business by reducing the total addressable market and by reducing the margin to cover the business’s logistics costs and other fixed expenses.

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.

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&power businesses are subject to regulatory risks mainly in our domestic market in Italy. 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,

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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 until the market is fully opened. Developments in the regulatory framework intended to increase the level of market liquidity or of de-regulation 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.

Risks related to environmental, health and safety regulations and legal risks

Eni has incurred in the past, and will continue incurring, material operating expenses and expenditures, and is exposed to business risk in relation to compliance with applicable environmental, health and safety regulations in future years, including compliance with any national or international regulation on GHG emissions

Eni is subject to numerous European Union, international, national, regional and local laws and regulations regarding the impact of its operations on the environment and on health and safety of employees, contractors, communities and on the value of properties. We believe that laws and regulations intended to preserve the environment and to safeguard health and safety of workers and communities are particularly severe in our businesses due to their inherent nature because of flammability and toxicity of hydrocarbons and of industrial processes to develop, extract, refine and transport oil, gas and products. Generally, 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 and of plants and infrastructures, the health of employees, contractors and other Company collaborators and of communities involved by the Company’s activities, and impose criminal or 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 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 polluting air emissions, as in the case of the European Trading Scheme that requires the payment of a tax for each tonne of carbon dioxide emitted in the environment above a pre-set allowance, 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. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste. Breaches of environmental, health and safety laws and regulations as in the case of negligent or wilful 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 of employees, contractors and other collaborators of the Company, and of communities, the Company may incur liabilities in connection with the negligent or wilful violation of laws by its employees as per Italian Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. 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:

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costs to prevent, control, eliminate or reduce certain types of air 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);

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remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below);

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damage compensation claimed by individuals and entities, including local, regional or state administrations, should Eni cause any kind of accident, oil spill, well blowouts, pollution, contamination, emission of GHG and other air pollutants above permitted levels or of any other hazardous gases, water, ground or air contaminants or pollutants, as a result of its operations or if the Company is found guilty of violating environmental laws and regulations; and

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costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging at the end of oil&gas field production.

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. For example, in Italy Eni has experienced in recent years a number of temporary plant shutdowns at our Val d’Agri oil treatment centre due to environmental issues and oil spillovers, causing loss of output and of revenues. The Italian judicial authorities have started legal proceedings to verify alleged environmental crimes or crimes against the public safety and other criminal allegations as described in the notes to the Consolidated Financial Statements.

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.

Climate-related risks

The civil society and the national governments adhering to the 2015 COP 21 Paris Agreement are stepping up efforts to reduce the risks of climate change and to support an ongoing transition to a low-carbon economy, which will likely lead to the adoption of national and international laws and regulations intended to curb carbon emissions, as well as to the implementation of fiscal measures which could possibly drive technological breakthrough in the use of hydrogen, exponential growth in the development of renewables energies and fast-growing adoption of electric vehicles, thus reducing the world’s economy reliance on fossil fuels. These trends could materially affect demand for hydrocarbons in the long-term, while we expect increased compliance costs for the Company in the short-term. Eni is also exposed to risks of unpredictable extreme meteorological events linked to climate change. All these developments may adversely and materially affect the Group’s profitability, businesses outlook and reputation

The civil society and the national governments adhering to the 2015 COP 21 Paris Agreement, with the EU playing a leading role, are advancing plans and initiatives intended to transition the economy towards a low-carbon model in the long run, as the scientific community has been sounding alarms over the potential, catastrophic consequences for human life on the planet in connection with risks of climate change, based on the scientific relationship between global warming and increasing GHG concentration in the atmosphere, mainly as a result of burning fossil fuels. This push, as well as increasingly stricter regulations in this area, could adversely and materially affect the Group’s business.

Those risks may emerge in the short and medium-term, as well as over the long term.

Eni expects that the achievement of the Paris Agreement goal of limiting the rise in temperature to well below 2° C above pre-industrial levels, or the more stringent goal advocated by the Intergovernmental Panel on Climate Change (IPCC) of limiting global warming to 1.5° C, will strengthen the global response to the issue of climate change and spur governments to introduce measures and policies targeting the reduction of GHG emissions, which are expected to bring about a gradual reduction in the use of fossil fuels over the medium to long-term, notably through the diversification of the energy mix, likely reducing local demand for fossil fuels and negatively affecting global demand for oil and natural gas.

Recently, governmental institutions have responded to the issue of climate change on two fronts: on the one side, governments can both impose taxes on GHG emissions and incentivise a progressive shift in the energy mix away from fossil fuels, for example, by subsidising the power generation from renewable sources; on the other side they can promote worldwide agreements to reduce the consumption of hydrocarbons. This trend has been progressively gaining traction with an increasing number of governments adopting national agendas and strategies intended to reach the goals of the Paris Agreement and formally pledging to obtain net-zero emissions by 2050, like the EU’s Green Deal, which may lead to the enactment of various measure to constrain, limit or prohibit altogether the use of fossil fuels. This trend could increase both in breadth and severity if more governments follow suit.

The dramatic fallout of the COVID-19 pandemic on economic activity and people’s lifestyle could possibly result in a breakthrough in the evolution towards a low-carbon model of development. The unprecedented contraction in economic activity caused by the lockdown measures adopted throughout the world to contain the spread of the virus, which resulted in the suppression of demand for hydrocarbons, could have an enduring impact on the future role of hydrocarbons in satisfying global energy needs. This is because many governments and the EU have deployed massive amounts of resources to help rebuild entire

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economies and industrial sectors hit by the pandemic-induced crisis and a large part of this economic stimulus has been or is planned to be directed to help transitioning the economy and the energy mix towards a low-carbon model, as in the case of the EU’s recovery fund, which provides for huge investments in the sector of renewable energies and the green economy, including large-scale adoption of hydrogen as a new energy source. At the same time, the auto industry is ramping up production of electric vehicles (EVs) and boosting the EVs line-up, while large amounts of risk capital and financing is propelling the growth of an entire new industry of pure-EV players. The growing role of EVs in transportation is leveraging on state subsidies to incentivize the purchase of EVs and growing interest among consumers towards EVs. Other potentially disruptive technologies designated to produce energy without fossil fuels and to replace the combustion engine in the transport sector are emerging, driven by the development of hydrogen-based innovations. These trends could disrupt demand for hydrocarbons in the not so distant future, with many forecasters, both within the industry, or state agencies and independent observers predicting peak oil demand sometimes in the next ten years or earlier; some operators still consider 2019 as the peak year for oil demand. 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 breakthrough in the field of renewable energies or mass-adoption of electric vehicles trigger a structural decline in worldwide demand for oil and natural gas, our results of operations and business prospects may be materially and adversely affected.

We expect our operating and compliance expenses to increase in the short-term due to the likely growing adoption of carbon tax mechanisms. Some governments have already introduced carbon pricing schemes, which can be an effective measure to reduce GHG emissions at the lowest overall cost to society. Today, 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), as a result of which the Company incurs operating expenses. For example, under the European ETS, Eni is obligated to purchase, on the open markets, emission allowances in case its GHG emissions exceed a pre-set amount of free emission allowances. In 2020 to comply with this carbon emissions scheme, Eni purchased on the open market allowances corresponding to 10.5 million tonnes of CO2 emissions. Due to the likelihood of new regulations in this area and expectations of a reduction in free allowances under the European ETS and of the adoption of similar schemes by a rising number of governments, Eni is aware of the risk that a growing share of the Group’s GHG emissions could be subject to carbon-pricing and other forms of climate regulation in the not so distant future, leading to additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could result in increased investments and higher project costs for Eni. Eni also expects that governments will require companies to apply technical measures to reduce their GHG emissions.

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.

Finally, there is a reputational risk linked to the fact that oil companies are increasingly perceived by institutions and the general public as entities primarily responsible for global warming due to GHG emissions across the hydrocarbons value-chain, particularly related with the use of energy products. This could possibly make Eni’s shares less attractive to investment funds and individual investors who have been more and more assessing the risk profile of companies against their carbon footprint when making investment decisions. Furthermore, a growing number of financing institutions, including insurance companies, appear to be considering limiting their exposure to fossil fuel projects, as witnessed by a pledge from the World Bank to stop financing upstream oil and gas projects and a proposal from the EU finance minister to reduce the financing granted to oil&gas projects via the European Investment Bank (EIB). This trend could have a material adverse effect on the price of our securities and our ability to access equity or other capital markets. Accordingly, our ability to obtain financing for future projects or to obtain it at competitive rates may be adversely impacted. Further, in some countries, governments and regulators have filed lawsuits seeking to hold fossil fuel companies, including Eni, liable for costs associated with climate change. Losing any of these lawsuits could have a material adverse effect on our business prospects.

As a result of these trends, climate-related risks could have a material and adverse effect 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.

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Eni is exposed to the risk of material environmental liabilities in addition to the provisions already accrued in the consolidated financial statement.

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. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. 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 conduct of prior operators or other third parties. 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 of violations of any environmental laws or regulations. In Italy, Eni is exposed to the risk of expenses and environmental liabilities in connection with the impact of its past activities at certain industrial hubs 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. At these industrial hubs, Eni has undertaken several initiatives to remediate and to clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. 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 perform. In some cases, Eni has been sued for alleged breach 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 costs to be incurred with respect to clean-ups and remediation of contaminated areas and groundwater for which a legal or constructive obligations exist and the associated costs can be reasonably estimated in a reliable manner, regardless of any previous liability attributable to other parties. The accrued amounts represent management’s best estimates of the Company’s existing liabilities. 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. As a result of these risks, environmental liabilities could be substantial and could have a material adverse effect 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.

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 notes to the condensed consolidated interim financial statements, under the heading “Legal Proceedings”. Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and

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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.

Internal control risks

Risks from acquisitions

Eni is constantly monitoring the oil and gas 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 so as 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 a prolonged decline in the market prices of oil and natural gas occurs. 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 materialise, expected synergies from acquisition may fall short of management’s targets and Eni’s financial performance and shareholders’ returns may be adversely affected.

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.

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 our 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, cyber-attacks (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.

Violations of data protection laws carry fines and expose us and/or our 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 we do business. The EU General Data Protection Regulation (GDPR) came into effect in May 2018 and increased penalties up to a maximum of 4% of global annual turnover for

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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 us to regulatory investigations, which could result in fines and penalties as well as harm our reputation. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. We 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.

Risks related to financial matters

Exposure to financial risk – We are exposed to treasury and trading risks, including liquidity risk, interest rate risk, foreign exchange risk, commodity price risk and credit risk and we may incur substantial losses in connection with those risks

Our business is exposed to the risk that changes in interest rates, foreign exchange rates or the prices of crude oil, natural gas, LNG, refined products, chemical feedstocks, power and carbon emission rights will adversely affect the value of assets, liabilities or expected future cash flows.

The Group does not hedge its exposure to volatile hydrocarbons prices in its business of developing and extracting hydrocarbons reserves and other types of commodity exposures (e.g. exposure to the volatility of refining margins and of certain portions of the gas long-term supply portfolio) except for specific markets or business conditions. The Group has established risk management procedures and enters into derivatives commodity contracts to hedge exposure to the commodity risk relating to commercial activities, which derives from different indexation formulas between purchase and selling prices of commodities. However, hedging may not function as expected. In addition, we undertake 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 risks of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.

We are exposed to the risks of unfavourable movements in exchange rates primarily because our consolidated financial statements are prepared in Euros, whereas our main subsidiaries in the Exploration & Production sector are utilizing the U.S. dollar as their functional currency. This translation risk is normally unhedged. Furthermore, our 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. 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 the U.S. dollar denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity.

We are exposed to fluctuations in interest rates that may affect the fair value of our financial assets and liabilities as well as the amount of finance expense recorded through profit. We enter into derivative transactions with purpose of minimizing our exposure to the interest rate risk.

Eni’s credit ratings are potentially exposed to risk from possible reductions of sovereign credit rating of Italy. On the basis of 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.

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We are exposed to credit risk; our counterparties could default, could be unable to pay the amounts owed to us in a timely manner or meet their performance obligations under contractual arrangements. These events could cause us to recognize loss provisions with respect to amounts owed to us by our debtors or in the worst case to write off a credit altogether. In recent years, the Group has experienced a significant level of counterparty default due to the severity of the economic and financial downturn that has negatively affected several Group counterparties, customers and partners and to the fact that Italy, which is still the largest market to Eni’s gas wholesale and retail businesses, has underperformed other OECD countries in terms of GDP growth. Those trends have been aggravated by the 2020 economic crisis caused by the lockdown measures adopted worldwide to contain the COVID-19 pandemic, resulting in a significantly deteriorated credit and financial profile of many of our counterparties, including national oil companies who are joint operators in our upstream projects, retail customers in the gas retail business and other industrial accounts. Therefore, in 2020 we incurred significant credit loss provisions based on management’s expectations of an increased default rate going forward, as the economic crisis is poised to continue affecting the financial conditions of our counterparties, and on evidence of our performance at collecting billed invoices in the retail gas&power business.

We believe that the retail gas & power segment is particularly exposed to credit risk due to its large and diversified customer base, which includes a large number of medium and small-sized businesses and retail customers who are expected to be particularly hit by the Italian economic recession. Eni’s Exploration & Production business is significantly exposed to credit risk because of the deteriorated financial outlook of many oil-producing countries due to the collapse recorded in crude oil prices and uncertainties about a stable recovery, which has negatively impacted petroleum revenues of those countries triggering financial instability. The financial difficulties of those countries have extended to state-owned oil companies and other national agencies who are partnering with Eni in the execution of oil&gas projects or who are buying Eni’s equity production in a number of oil&gas projects. These trends have limited Eni’s ability to fully recover or to collect timely its trade or financing receivables or its investments towards those entities. Eni believes that the management of doubtful accounts in the post pandemic environment represents a risk to the Company, which will require management focus and commitment going forward. Eni cannot exclude the recognition of significant provisions for doubtful accounts in future reporting periods. Management is closely monitoring exposure to the counterparty risk in its Exploration & Production business due to the magnitude of the exposure at risk and to the long-lasting effects of the oil price downturn on its industrial partners.

If any of the risks set out above materialises, 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.

Liquidity risk

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 in order 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. Global financial markets are volatile due to several macroeconomic risk factors, including the fiscal outlook of the hydrocarbons-producing countries. In 2020, due to a collapse in hydrocarbons consumption and prices caused by an almost standstill of the global economy and travel in response to the COVID-19 pandemic, we experienced a material contraction in our cash flows from operations, which reduced the Company’s cash reserves. We were forced to reduce a significant portion of our liquidity reserves and we tapped the financial markets, as we managed through the downturn. We did not incur worsened borrowings conditions with respect to standard market terms or past fiscal years, nor were our finance expenses unusually high. However, due to an increase in the Company’s net exposure towards the financial system and indebtedness ratio, our liquidity risk profile has deteriorated. In case of new restrictive measures in response to a resurgence of the pandemic leading 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, we may incur significantly higher borrowing costs than in the past or difficulties obtaining the necessary financial resources to fund our development plans, therefore jeopardizing Eni’s ability to maintain long-term investment programs. Low investments to develop our reserves may significantly and negatively affect Eni’s business prospects, results of operations and cash flows, and may impact shareholder returns, including

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dividends or share price. The oil and gas industry is capital intensive. Eni makes and expects to continue to make substantial capital expenditures in its business for the exploration, development and production of oil and natural gas reserves. Over the next four years, the Company plans to invest in the oil&gas business approximately an average of €4.5 billion per year. In 2021, Eni expects to make capital expenditures slightly below the level of €6 billion, of which about 70% in the Exploration & Production segment, at the planned exchange rate of 1.19 USD/EUR. 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, 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 a number of variables, including but not limited to:

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the amount of Eni’s proved reserves;

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

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the prices at which crude oil and natural gas are sold;

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

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the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds.

If revenues or Eni’s ability to borrow decrease significantly due to factors such as a prolonged decline in crude oil and natural gas prices, Eni might have limited ability to obtain the capital necessary to sustain its planned capital expenditures. If cash generated by operations, cash from asset disposals, or cash available under Eni’s liquidity reserves or its credit facilities 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 business, financial condition, results of operations, and cash flows and its ability to achieve its growth plans. These factors could also negatively affect shareholders’ returns, including the amount of cash available for dividend distribution and share repurchases, as well as the share price. In addition, 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 and principal on its debt, thereby reducing its ability to use cash flows to fund capital expenditures and dividends.

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Item 4. INFORMATION ON THE COMPANY

History and development of the Company

Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders.

The 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 and with the aim of reaching the target of net zero emissions of carbon dioxide (“CO2”) by 2050 to comply with the climate target of the Paris Agreement. According to the management, this strategic shift away from traditional hydrocarbon 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.

In June 2020, Eni’s Board of Directors established a new organizational structure with two business groups to align with the Company’s decarbonization strategy. The “Natural Resources” business group is responsible for enhancing the oil & gas portfolio of the Exploration & Production (“E&P”) segment in a sustainable manner, focusing also on energy efficiency activities, projects for forests conservation (REDD+) and projects for the capture, storage and/or utilization of CO2 (“CCS” or “CCU”). In addition to E&P, this business group comprises the wholesale gas and LNG businesses as well as the activity of environmental protection and remediation managed by our subsidiary Eni Rewind. The other business group “Energy Evolution” is responsible for progressing and developing the renewable businesses of generating and selling renewable power and manufacturing and marketing sustainable products obtained from decarbonized industrial processes (blue products) and by biomass (bio-products). This business group comprises the Refining & Marketing business, the chemical business managed by Versalis SpA and its subsidiaries, the retail gas and power business managed by Eni gas e luce and the business of producing and selling power from thermoelectric plants and renewable sources.

In re-designing the Group’s segment information for financial reporting purposes, management evaluated that the components of the Company whose operating results are regularly reviewed by the CEO (Chief Operating Decision Maker as defined by IFRS 8) to make decisions about the allocation of resources and to assess performance would continue being the single business units which are comprised in the two newly-established business groups, 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 new reportable segments of Eni, substantially confirming the pre-existing setup, are identified as follows:

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Exploration & Production, which also comprises the economics of the forestry projects (REDD+) and projects for CO2 capture and storage and/or utilization. Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 42 countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and United Arab Emirates. In 2020, Eni average daily production amounted to 1,609 KBOE/d on an available- for-sale basis. As of December 31, 2020, Eni’s total proved reserves amounted to 6,905 mmBOE, which include subsidiary undertakings and proportionally consolidated entities and Eni’s share of reserves of equity-accounted joint ventures and associates.

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Global Gas & LNG Portfolio: engages in the wholesale activity of supplying and selling natural

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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 2020, Eni’s worldwide sales of natural gas amounted to 64.99 BCM, of which 37.30 BCM was in Italy. The LNG business includes the purchase and marketing of LNG worldwide, with a large proportion of equity LNG supplies.

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Refining & Marketing and Chemicals: engages in the manufacturing, supply and distribution and marketing activities of oil products and chemical products and in trading activities. The results of operations of the R&M business and of the chemical business have been combined in a single reporting segment because the two businesses exhibit similar characteristics. Oil and products trading activities are designed to perform supply balancing transactions on the market and to stabilize or hedge commercial margins. The R&M business engages in crude oil supply and refining and marketing of petroleum products to the cargo market, to large business accounts (airlines companies, bunker, public administrations, operators of privately-held networks of service stations) and to retail customers through a network of proprietary or leased service stations in Italy and in the rest of Europe. Production of refined products derives from both oil-based refineries and from manufacturing processes based on renewable feedstock. As of December 31, 2020, the balanced refining capacity was 548 KBBL/d. In 2020, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to 17.71 mmtonnes (of which traditional refinery throughputs were 17 mmtonnes and bio refinery throughputs were 0.71 mmtonnes) and sales of refined products were 26.08 mmtonnes, of which 20.02 mmtonnes were in Italy. Retail sales of refined products at Eni’s service stations amounted to 6.61 mmtonnes in Italy and in the rest of Europe. In 2020, Eni’s retail market share in Italy through its “Eni” branded network of service stations was 23.3%. 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 green chemicals. Activities are concentrated in Italy and in Europe. In 2020, production volumes of petrochemicals amounted to 8,073 ktonnes.

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Eni gas e luce, Power & Renewables: engages in the activities of retail marketing of gas, power and related services, as well as in the production and wholesale marketing of power produced by both thermoelectric plants and from renewable sources. It also comprises trading activities of CO2 emission allowances and of forward sales of power to help stabilize/hedge the clean crack spreads of power sales. As at December 31, 2020, Eni customer base was 9.6 million retail points of delivery (gas and electricity) in Italy and Europe (of which 7.7 million were in Italy). In 2020, retail power sales to end customers, managed by Eni gas e luce and subsidiaries companies in France and Greece, amounted to 12.49 TWh. Retail gas sales, in Italy and in European markets, amounted to 7.68 BCM. As of December 31, 2020, installed operational capacity of Enipower’s power plants was 4.6 GW. In 2020, thermoelectric power generation was 20.95 TWh. Eni is engaged in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore) through the business unit Energy Solutions which engages in building, commissioning and managing renewable energy producing plants. At the end of 2020, the total installed and sanctioned capacity amounted to 1 GW, of which the total installed capacity for the generation of energy from renewable sources amounted to 307 MW (in Eni share and including the storage power).

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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.

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

Eni branches are located in:

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

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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 adapt its business model and to grow in a low-carbon economy. Our long-term goal is to reach the carbon-neutrality of our industrial processes and products by

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2050, covering GHG scope 1, 2 and 3 emissions, in line with the goals set by the Paris Agreement on climate, which we fully endorse. The evolution of our business model and the underlying action plan will be accomplished over a thirty-year timeframe and will significantly increase the weight of fully-decarbonized products in our portfolio, while progressively reducing the Company’s exposure to traditional hydrocarbons products, capitalizing on the opportunities arising from a rapidly-changing energy landscape. The strategic guidelines that will drive our evolution going forward are:

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To actively contribute to the achievement of the 17 UN SDGs which are reflected in Eni’s mission, particularly the goals of improving air quality and securing universal access to energy;

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To maximize the integration of the portfolio along the entire value chain;

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To retain a financial framework which prioritizes capital discipline and a strong balance sheet;

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To improve the Group’s resilience to the oil scenario, also by reducing the exposure to the traditional oil-based businesses and growing the weight of the green/retail/circular economy businesses;

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To leverage the technology to speed up the business evolution; and

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To achieve a competitive, progressive shareholders’ distribution policy.

In the short-term, while progressing the transformation of its business model, the Company’s priorities will be to shore up its cash flow and to improve its financial resilience which have been significantly and adversely affected by the consequences of the COVID-19 pandemic on worldwide economic activity and human life.

In 2020, the Company was confronted with a challenging trading environment because the pandemic crisis drove a collapse in hydrocarbons demand, which pressured prices and margins of hydrocarbons. To contain the spread of the virus, governments throughout the world imposed tough lockdown measures which caused an unprecedented contraction in economic activity, international commerce and travel particularly in the second quarter of 2020, leading to a massive decline in demand for fuels and other hydrocarbons-based commodities. Prices for crude oil and natural gas plunged to multi-year lows at the peak of the crisis, during the March-April period, with the price of the Brent crude oil benchmark down to an historic low at around 15 $/bbl. The subsequent recovery in crude oil prices was supported by a rebound in economic activity, mainly in China and other parts of Asia, and by the huge production cuts implemented by the OPEC+ producers starting in May 2020. However, the recovery was not enough to overcome the losses incurred in the second quarter, because gains in crude oil prices were capped by a continuing rise in new virus cases particularly in the United States, continental Europe and the UK, while many people stayed at home and worked remotely, thus depressing demand for gasoline and other fuels. This situation explained why refining margins fell to record lows in the third and fourth quarter of 2020, while crude oil prices hovered around 40 $/bbl. Finally, the recovery in crude oil prices gained strength in the final months of 2020 and at the beginning of 2021 due to a combination of market and macro developments, most notably: substantial progress in developing vaccines against the virus, continuing production discipline on part of OPEC+ producers with the surprising announcement of further production cuts by the Saudi Arabia in early January 2021 and finally the outcome of the U.S. presidential election which boosted expectation for massive stimulus measures of the economy. Crude oil prices closed the year at about 50 $/bbl vs. an average price of approximately 42 $/bbl for the FY 2020, then the recovery gained steam in January through March 2021, with the average Brent price for the first quarter of 2021 above 60 $/bbl. However, the recovery has yet to be felt in the refining sector, where margins have continued to be depressed because of millions of people still locked down.

The hydrocarbons crisis of 2020 materially and adversely hit the Company’s results of operations and cash flows with an estimated loss of approximately €7 billion due to lower hydrocarbons prices and other COVID-related effects, net of management’s initiatives to cope with the downturn. Confronted with such a shortfall and an uncertain path to a demand recovery due to elevated risks of new, virus-induced economic lockdowns and travel restrictions as well as economic downturn, the Company has taken a number of steps to strengthen its balance sheet and to improve the financial resiliency of its operations, while maintaining its focus on implementing its decarbonization strategy. We plan to retain strict capital discipline in investment decisions going forward and to allocate cash prioritizing the preservation of a healthy balance sheet, shareholder returns, and an ongoing expansion into the low-carbon businesses.

The steps taken so far to deal with the effects of the 2020 downturn in the hydrocarbon sector on the Company’s results and financial position and our forecast actions for 2021 and the medium term are described below:

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During the peak of the crisis, we revised our operating plans for the remainder of 2020 and for 2021, resolving to reduce the cash outlays for capital expenditures and operating expenses by approximately €8 billion in that period.

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As part of the €8 billion amount, we delivered a reduction of €2.6 billion in capital expenditures, equaling a cut of 35% of the original amount budgeted for 2020, and €1.9 billion of lowered operating expenses, of which 30% of structural nature. The reduction of capital expenditures was concentrated almost entirely in the E&P segment, where we could leverage on project re-phasing and remodulation to achieve the expected savings, with the option of resuming the delayed or suspended project phases once the scenario normalizes.

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We are planning to invest an average yearly amount of less than €7 billion of organic expenditures in the business over the next four-year planning period compared to a level of €8 billion per year in previous planning assumptions before the COVID-19 crisis, to factor in expected risks and uncertainties about the recovery, thus signaling a more prudent approach to investment decisions than in the past. For 2021, we forecast a level of expenditures slightly below €6 billion;

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Approximately 20% of the capex plan will be allocated to growing our decarbonized businesses, particularly the generation capacity of renewable power, the manufacturing capacity of biofuels, the expansion of our customer portfolio in the retail marketing of gas and power and the development of circular economy projects.

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We have established a new, flexible distribution policy based on a fixed dividend plus a variable component linked to trends in the oil scenario. This new policy was initially announced to the market in July 2020, when we established a floor dividend of €0.36 per share at an oil price environment of at least 45 $/bbl of Brent. The floor dividend is expected to be reassessed periodically to factor in the Company’s progress at delivering on its strategy and industrial targets. For fiscal year 2020, management resolved to distribute the base dividend of €0.36 per share notwithstanding the yearly average price of the Brent crude oil was 42 $/bbl, lower than the internally set threshold. This policy was updated in February 2021, when the Company set its strategies and targets for the four-year plan 2021-2024 and the long-term. Going forward, the floor dividend of €0.36 per share is planned to be paid at an average Brent scenario of 43 $/bbl for the reference year and a variable dividend is expected to be paid as a function of an expected growth in cash flow driven by rising oil prices above the threshold of 43 $/bbl up to 65 $/bbl. See Item 5 – Management Expectations of Operations.

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In 2020, in order to preserve the Company’s cash flow we decided to suspend the buy-back program of Eni’s shares. In our strategic update of February 2021, we reaffirmed our commitment to resume the buy-back of Eni’s shares and we lowered the Brent price threshold where the buy-back is expected to resume. We are now forecasting to allocate €300 million per year to the repurchase of Eni’s shares provided that the Brent price is not lower than 56 $/bbl; that amount will ramp-up to €400 million provided that the Brent price is not lower than 61 $/bbl and to €800 million from 66 $/bbl, which were the triggering prices of our prior shareholder return policy.

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Our oil&gas production plans have been revised to discount our changed cash allocation priorities and reduced expenditures to develop our reserves both in 2020 and in the following years. In 2020, our oil&gas production on an available-for-sale basis averaged 1,609 KBOE/d which was negatively affected by capex curtailments, OPEC+ production quotas, lower gas demand and other operating factors. For 2021, we expect flat oil&gas production as compared to the prior year, assuming OPEC+ cuts of about 40 kBOE/d in the year. We anticipate production growth to resume in the subsequent years of our plans, as we are targeting an average growth rate of 4% in the four-year period 2021-2024. Despite strict capital discipline, we expect our future growth rate to be supported by continuing exploration success in proven and mature areas where the discovered resources can be developed by means of existing facilities and infrastructure without incurring additional expenses, the ramp-up/start-up of certain large projects where the majority of development expenses have already been incurred, planned production growth at our equity-accounted investments and an easing of the production cuts enacted by OPEC.

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We are assuming a long-term crude oil price of the Brent benchmark at 60 $/bbl in real terms 2023 (nominal growth rate of 2% from 2024 onwards) – revised down from our prior assumption of 70 $/bbl — for our planning assumptions, investment decision processes and evaluation of the recoverability of the carrying amounts of oil&gas assets.

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In E&P, we plan to maximize the cash generation by growing production profitably, by retaining strict capital discipline in selecting exploration and development projects and by strengthening the resiliency of our portfolio made up of conventional oil&gas assets. Our goal is to reduce the Brent price at which the business can fund its capital expenditures needs through internally generated funds, leveraging the quality of its asset portfolio consisting of assets with low breakeven prices and fast time-to-market. The business will also advance several projects designed to address the issue of the decarbonization of the Group products, most notably two large projects which are in the pre-feasibility stage designed to capture carbon dioxide and store it at depleted offshore natural gas field in the northern section of the Adriatic Sea (Italy) and in the Liverpool Bay (UK). We plan to build an underground capacity to store up to 7 million tons per year of CO2 by 2030 (Eni’s share, corresponding to a gross capacity of 15 MTPA). Furthermore, we plan to ramp up a set of actions designated to sink CO2 by means of participating in projects for preserving forests (the so called REDD+ projects), targeting obtaining allowances to offset carbon emissions for an amount of 6 million tonnes per year in 2024 and more than 20 million by 2030.

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In the Global Gas & LNG Portfolio business, we plan to hold steady profitability and cash generation, leveraging on the continuing renegotiation of our long-term gas supply contracts to align pricing and other terms to changing market conditions, on the optimization of logistic costs and on an expected growth in the LNG business. We also plan to strengthen the integration with the E&P with the objective of extracting the full value from the equity production of natural gas by trading increasing volumes of LNG equity. Contractual LNG volumes are expected to exceed 14 million tons per year, up 45% from 2020.

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In the R&M segment, we plan to restore the profitability of the traditional business of manufacturing oil-based fuels and other products via plant optimizations, capital discipline and cost savings and to fully realize the value of our investment in ADNOC R&T with the help of a new platform to trade oil and other commodities. We will expand the business of manufacturing biofuels targeting approximately 2 million tons of capacity by the end of 2024, at the same time advancing the process of feedstock diversification in running our bio-refineries by zeroing the use of palm oil in 2023, whose target is seven years ahead of the EU ban on palm oil, while growing the share of feedstock coming from waste and residues covering approximately 80% of the total processed volumes in 2024, up from the current 20% share.

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In the petrochemicals business, we plan to restore the profitability of our operations by means of further plant integrations and optimizations by right-sizing the production capacity of basic commodities to align to the needs of downstream markets and cost-cutting measures. We will seek to reduce our exposure to the margin volatility of oil-based petrochemicals products by expanding our presence in the niche of high-quality and high-performance polymers and to develop and integrate the new businesses of producing chemicals products from renewables and from the re-use of wasted plastics through processes of mechanical recycling and via chemical treatment processes based on the pyrolysis of the non-recyclable fraction of utilized plastics.

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In the gas&power retail marketing business, we plan to improve the profitability of our operations, which will be driven by an expected growth of our customer base, the offering of innovative products and services with a rising weight of decarbonized commodities, as well as by improving customers’ experience and effective marketing processes. Our goal is to increase the number of our clients from 9.6 million at the end of 2020 to 11 million units by 2024, also leveraging the integration with our business of renewable power which is expected to be merged with our subsidiary Eni gas e luce which is engaged in the retail gas&power business.

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In the business of renewable power, we plan to aggressively expand the installed capacity of solar power and of both onshore and offshore wind power targeting an installed capacity of approximately 4 gigawatts by 2024, leveraging on our pipeline of projects already sanctioned or under construction as well as our participation in equity-accounted ventures and initiatives.

We believe the outlined actions will improve the Group financial resiliency and cash flow in the coming years. We expect the Group’s balance sheet to strengthen going forward under our assumption of a modest recovery in Brent crude oil prices that are projected to increase from 50 $/bbl in 2021 up to 60 $/bbl in 2023 and to progressively reduce the Group’s cash neutrality, i.e. the level of Brent crude oil price at which the Group is able to fund the planned organic capital expenditures (i.e. before acquisitions) and the floor dividend to below 40 $/bbl at the end of the four-year plan.

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Carbon footprint

Eni, is aware of the ongoing climate emergency and intends to play a key role in the commitment of the energy sector contributing to carbon neutrality by 2050, in order to keep global warming within the threshold of 1.5° C at the end of the century.

The strategy and the action plan designed by the Company for the medium and the long-term will drive a significant improvement in our carbon footprint with the objective to become carbon neutral by 2050. Eni pursues a strategy that aims to reach the net zero target on our GHG emissions covering scope 1, 2 and 3, both in absolute and relative terms, which will be supported by continued advances and progress that we expect to achieve in the short and medium-term.

To evaluate our emissions, we have adopted a fully comprehensive lifecycle approach that takes into account all the energy products sold and traded by our organization and the GHG emissions they generate along their value chains.

The implementation of our strategy and of our action plan over the next thirty years will drive:

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an absolute reduction in net lifecycle GHG emissions (scope 1, 2 and 3) by 25% in 2030 and by 65% by 2040 vs the 2018 baseline, reaching net zero in 2050 in line with low carbon scenarios compatible with the aim of limiting global warming to 1.5 C°

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a reduction of 15% and 40% in net carbon intensity per unit of energy product sold respectively by 2030 and 2040 vs the 2018 baseline. In 2050 we target net zero carbon intensity.

Other intermediate targets of de-carbonization include:

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net zero carbon footprint by 2030 for scope 1 and 2 emissions in the E&P business, accounted on equity basis; and

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net zero carbon footprint by 2040 for Eni’s scope 1 and 2 emissions.

The actions mostly yet to be put in place to drive our carbon footprint reduction are:

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progressive reduction of the hydrocarbons production in the medium long term, with an increasing share of gas in our portfolio, reaching 90% in the energy mix in 2050. At the same time, we will seek to retain the ability to modulate future investments in exploration and development to enable the Company to capture market opportunities as they evolve. We expect to produce a large part of the value of our reserves by 2035 under the most conservative scenario assumptions;

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progressively upgrade traditional refineries through new technologies, to value decarbonized products and waste material recycling, to hubs to produce hydrogen, methanol, bio-methane;

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increase the focus on equity gas in Global Gas & LNG Portfolio, progressively reducing the marketing of gas purchased from third parties;

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expand production capacity for manufacturing biofuels in the long-term to over 5 million tonnes per year in 2050, utilizing exclusively feedstock which are compatible with the environment (palm oil free starting from 2023);

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evolve the product mix marketed to our retail customers, with the aim to reach 100% of de-carbonized products by 2050;

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expand the business of circular economy, which comprises several business initiatives designed to make the best use of industrial and civil waste, both organic and inorganic, through re-use or recycling aiming at producing energy feedstock and reusable finished products;

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scale up the business of power generation from renewable sources, targeting a progressive expansion of the installed global capacity with the aim to reach 60 GW by 2050;

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increase the production of green and blue hydrogen coupled with projects to capture and store CO2;

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expand retail activities to reach a customer base of over 20 million by 2050, leveraging the expected growth in consumption of renewables and bio-methane;

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build and operate projects of carbon capture and storage (CCS) with the goal of capturing up to 50 million tons per year (MTPA) of CO2, once our projects reach full capacity in 2050, with intermediate target of 7 MTPA in 2030;

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ramp up the participation in projects for forest conservation and preservation with the goal of obtaining allowances to offset up to 40 MTPA of CO2, in 2050, with an intermediate target more than 6 MTPA in 2024 and 20 MTPA in 2030.

One of the milestones of our decarbonization strategy is to achieve by 2030 a net zero carbon footprint in our E&P business relating to scope 1 and 2 emissions on equity basis, with an intermediate target of 50% reduction in 2024 vs. 2018. We are planning to reach this goal:

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by increasing efficiency to minimize direct upstream CO2 emissions. As part of this target by 2025 we plan to eliminate routine gas flaring at our industrial processes to extract and treat hydrocarbons and reduce fugitive methane emissions by 80% in our operated assets; and

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by offsetting residual upstream emissions through the ramp up of our projects designed to build carbon sinks like the projects for the conservation of primary and secondary forests, projects for the capture and storage of carbon dioxide leveraging our technologies and availability of depleted reservoirs, as well as for carbon capture and reuse which aim at recycling the carbon dioxide to manufacture valuable basic materials (see paragraph “Research&Development” below, for information about those technologies).

Our portfolio of oil and gas properties features a large weight of natural gas, the least GHG-emitting fossil energy source, which represented approximately 48% of Eni’s production in 2020 on an available-for-sale basis; as of December 31, 2020, gas reserves represented approximately 49% of Eni’s total proved reserves of its subsidiary undertakings and joint ventures. The other pillar of our resilient portfolio of oil&gas properties is the high incidence of conventional projects, developed through phases and with low CO2 intensity. We estimate that oil&gas projects under execution, which will drive the expected production increase in the next four-year period and attract a large part of the projected development expenditures in the same period, have a price breakeven of around 23 $/bbl. We believe that those characteristics of our portfolio coupled with a relatively low pay-back period will mitigate the risk of stranded reserves going forward, should risks of structurally declining hydrocarbons demands materialize because of stricter global environmental constraints and regulations and changing consumers’ preferences resulting in trends like the mass adoption of electric vehicles or a lower weight of hydrocarbons in the energy mix.

Eni’s portfolio exposure to those risks is reviewed annually against changing GHG regulatory regimes, evolving consumers’ habits, technological developments and physical conditions to identify emerging risks. To test the resilience of new capital projects, Eni assesses potential costs associated with GHG emissions and their impact on projects’ returns. New projects’ internal rates of return are stress-tested against two sets of assumptions: i) Eni’s management estimation of a cost per ton of carbon dioxide (CO2), which is applied to the total GHG emissions of each capital project along its life cycle, while retaining the management scenario for hydrocarbons prices; and ii) the hydrocarbon prices and cost of CO2 emissions adopted in the International Energy Agency (IEA) Sustainable Development Scenario “IEA SDS” WEO 2020. This stress test is performed on a regular basis to monitor progress and risks associated with each project. The review performed at the end of 2020 indicated that the internal rates of return of Eni’s ongoing projects in aggregate should not be substantially affected by a carbon pricing mechanism, also under the assumption that the costs for emission allowances are not recoverable in the cost oil or are not deductible from profit before taxes. This observation holds true also under the more severe CO2 pricing assumptions of the IEA SDS scenario. The development process and internal authorization procedures of each E&P capital project feature several checks that may require additional and well detailed GHG and energy management plans to address potential risks of underperformance in relation to possible scenarios of global or regional adoption of regulations introducing mechanisms of carbon cap and trade or carbon pricing. These processes and internal authorization hurdles can lead to projects being stopped, designs being changed, and potential GHG mitigation investments being identified, in preparation for when the economic conditions imposed by new regulations would make these investments commercially compelling.

Furthermore, management performed a sensitivity analysis of the recoverability of the book values of the Company’s oil & gas assets under the assumptions set forth in the IEA SDS WEO 2020 to evaluate the reasonableness of the outcome of impairment review of those assets under the base case management scenario as well as possible risks of stranded assets. This stress test covered all the oil & gas cash generating unit (CGUs) that are regularly tested for impairment in accordance to IAS 36. The IEA SDS sets out an energy pathway consistent with the goal of achieving universal energy access by 2030 and of reducing energy-related CO2 emissions and air pollution in line with the goals of the Paris Agreement which endorse effective action to combat climate change by holding the rise in global average temperature to well below 2°C with respect to the baseline before the Industrial Revolution and to pursuing efforts to limit it to 1.5°C.

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The hydrocarbon pricing assumptions of the IEA SDS scenario are substantially aligned to the ones adopted by Eni in its base case impairment review made in accordance with IAS 36. CO2 emissions costs under the IEA SDS show a strong uptrend consistent with the goal of encouraging the adoption of low carbon technologies. The IEA SDS projects CO2 emissions costs in advanced economies to reach 140 $ per ton in real terms 2019 by 2040, which is higher than Eni’s CO2 pricing trends and assumptions for the medium-long term. The sensitivity test performed at Eni’s oil&gas CGUs under the IEA SDS assumptions and applying the CO2 cost estimated by the IEA for advanced economies to all of our oil and gas assets validated the resiliency of Eni’s asset portfolio, determining a reduction of 11% in the total value-in-use of all of Eni’s oil&gas CGUs compared to the result of the impairment review performed by the Company in the preparation of its 2020 financial statements using the management’s base case scenario. That reduction falls to a 5% decline assuming the recoverability of CO2 costs in the cost oil or the deductibility from the taxable income.

Finally, management considered the following trends in the sector: the increased volatility of crude oil prices which have been increasingly exposed to macro and global risks; the continued oversupply in the oil markets which has determined a reset in hydrocarbons realized prices and cash flows of oil companies; growing uncertainty about long-term evolution of global oil demand in light of the rising commitment on the part of the international community at addressing climate change and speeding up the pace of the energy transition, the increase in energy alternatives to fossil fuels and changing consumer preferences, management has evaluated the recoverability of the book values of Eni’s oil&gas properties under different stress-test scenarios, including the risk of stranded assets. Particularly, under the more conservative set of the assumptions which envisages a flat long-term Brent price of 50 $/bbl and at a flat Italian gas price of 5 $/mmBTU, management is estimating that approximately 81% of the volumes of the Company’s proven and unproven reserves (latter being properly risked) will be produced within 2035 and 93% of their net present value will be realized. The net present value of those production volumes, valued at the most conservative of the scenarios evaluated, is substantially aligned with the book values of the net fixed assets of Eni’s oil&gas properties, including Eni’s share of the fixed assets of our joint ventures like Vår Energi AS, and including in the calculation the expected cash outflows committed to the Company’s forestry projects.

In October 2018 the Intergovernmental Panel on Climate Change (IPCC) stated that to reduce risks of irreversible changes to the ecosystem the world economy needs to limit the increase in global temperatures to 1.5°C. To meet this challenge, the world economy would need to undertake in the next decades a deeper and more complex transformation, both in term of size and speed, than the one foreseen in the Paris Agreement. Recognizing the IPCC position, the IEA has elaborated in its WEO 2020 a new detailed modelling called the Net Zero Emissions 2050 case (NZE2050) to examine what more would be needed compared to the SDS in next decade to put global CO2 emissions on a pathway to net zero by 2050. The set of actions contemplated by the IEA NZE2050 case comprise a dramatic increase in investments in low-emission electricity, infrastructure and innovation as well as demanding behavioral changes on part of the consumers. Currently, this scenario like the one outlined by the IPCC have yet to be complemented by a full set of pricing and other operating assumptions, which once available will be analyzed by the Company for the purpose of updating stress-testing models and methodologies.

Significant business and portfolio developments

•

March 2021 - Signed a Memorandum of Understanding with Zhejiang Energy company across the gas and LNG value chain in China and internationally, establishing a cooperation framework aimed at facilitating joint initiatives and promoting a reduction in emissions by favoring a switch from coal to gas in the production of electricity.

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March 2021 - Versalis, Eni's chemical company, signed a development agreement with Bridgestone EMIA, a leader in advanced mobility solutions, for the research, production and supply of synthetic rubber with advanced properties.

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March 2021 – Made one oil discovery in the production licence 532 (Eni’s interest 21%) in the Barents Sea and in the production licence 090/090I (Eni’s interest 17%) in the northern North Sea, offshore Norway.

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March 2021 – Signed an agreement to acquire the FRI-EL Biogas Holding company, a leader in the Italian biogas production sector. With this agreement, Eni strengthening its growth in the circular economy, laying the foundations to become the first producer of biomethane in Italy.

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March 2021 — UK Research and Innovation (UKRI), country’s authority for research and innovation, will fund the CCS projects developed by Eni and other partners: (i) the HyNet North

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West integrated project with approximately £33 million (£21 million net to Eni); and (ii) the Net Zero Teeside and North Endurance Partnership projects with approximately overall £52 million (£9 million net to Eni). The grants will finance 50% of the ongoing design studies and accelerate the final investment decision for all projects, expected in 2023.

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March 2021 – Established GreenIT (Eni’s interest 51%), a joint venture with the Italian agency CDP Equity, for building, commissioning and managing plants for the production of power from renewable sources in Italy, with the aim of reaching an installed capacity of approximately 1,000 MW by 2025, with cumulative investments amounting to over 800 million euro in the five-year period.

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March 2021 – Finalized a series of agreements with the Arab Republic of Egypt (ARE) and the Spanish partner Naturgy for the restart of the Damietta liquefaction plant and the resolution of all pending issues of the JV Uniòn Fenosa Gas with the Egyptian partners and the subsequent restructuring of the venture, which assets will be split between the two shareholders. The LNG production restarted in February 2021. The liquefaction plant in Egypt has produced and lifted its first LNG cargo since the terminal was shut down in 2012, representing a milestone in the process to complete the agreement reached on December 1, 2020 aimed at settling all pending disputes between the parties and at restarting the operations at the plant. The restart of the plant was a condition precedent to the effectiveness of a restructuring plan of the Union Fenosa Gas joint venture providing for a break-up of the venture. The deal will strengthen Eni’s portfolio of LNG by retaining a 50% stake in the ownership of the Damietta plan and other activities and allow Eni to directly enter the Spanish gas market. No significant impacts on the Group cash position are expected following the completion of the transaction.

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March 2021 – Signed an agreement to divest the entire upstream activity in Pakistan, including interests in eight development and production licenses, to Prime International Oil&Gas, a local company. The agreement provides for the disposal of the Bhit/Badhra (Eni’s interest 40%) and Kadanwari (Eni’s interest 18.42%) operated fields and the participating interest in the Latif (Eni’s interest 33.3%), Zamzama (Eni’s interest 17.75%) and Sawan (Eni’s interest 23.7%) fields.

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February 2021 – Restarted LNG production in Damietta. The liquefaction plant in Egypt has produced and lifted its first LNG cargo since the terminal was shut down in 2012. Such event represents a milestone in the process to complete the agreement reached on December 1, 2020 aimed at settling all pending disputes between the parties and at restarting the operations at the plant. The restart of the plant was a condition precedent the efficacy of a restructuring plan of the Union Fenosa Gas joint venture providing for a break-up of the venture. Following the completion of the plan, Eni is retaining a 50% stake in the ownership of the Damietta plan and other activities.

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February 2021 – Signed an agreement with X – Elio for the acquisition of three photovoltaic projects in Spain for a total capacity of 140 MW.

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February 2021 – Launch of a plan to build a hub for the capture and storage of CO2 in depleted fields off the coast of Ravenna (Italy, near the Po delta) which will be designed to store more than of 500 million tonnes per year of CO2. The project will benefit on the expected synergies on development cost due to the infrastructure in place. The program includes: (i) a pilot project with start-up expected in 2022 following all necessary authorizations; and (ii) a full development phase expected to commence in 2026.

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February 2021 – Signed a cooperation agreement with other upstream partners for the Net Zero Teeside (Eni’s interest 20%) and North Endurance Partnership (Eni’s interest 16.7%) projects. These integrated projects will allow to target the decarbonization of the Teeside industrial area, in the north east UK, by means of the transportation and storage of CO2. Start-up is expected in 2026 with a carbon capture and storage of 4 million tonnes per year.

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February 2021 – Signed an agreement with Be Charge, to increase the national supply of charging infrastructures for electric mobility. The charging station will be powered by renewable energy to be supplied by Eni gas e luce.

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January 2021 – Awarded the operatorship of the exploration license P2511 (Eni’s interest 100%) in the North Sea in the United Kingdom.

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January 2021 – Signed an agreement to acquire 100% of Aldro Energía, with a portfolio of approximately 250,000 customers located in Spain and Portugal. The transaction will be completed upon receipt of the authorizations by the relevant authorities.

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January 2021 – Awarded 10 new exploration licenses to Vår Energi in Norway, with 5 operatorships.

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January 2021 – Signed a Memorandum of Understanding (MoU) between Eni Rewind and NOGA (National Oil and Gas Authority) of the Kingdom of Bahrain with the aim of promoting joint initiatives for the management, recovery and reuse of water, soil and waste in Bahrain.

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January 2021 – Started up gas production in the Sharjah Emirate (UAE), at the Mahani exploration prospect (Eni’s interest 50%) in the onshore Concession B, just one year since discovery and two years after signing the concession agreement.

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December 2020 – Made an oil discovery, in Meleiha Concession, in the Western Desert of Egypt. The discovery adds 10,000 barrels of oil per day to the current production of the Concession.

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December 2020 – Started a strategic collaboration with the Italian agency CDP and Snam in the field of the energy transition, which includes the study of joint projects in key segments such as the hydrogen supply chain, circular economy (including the use of biomethane) and sustainable mobility.

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December 2020 – Awarded the operatorship of the offshore Block 3 (Eni’s interest 70%) of approximately 12,000 square kilometers, in the United Arab Emirates with near-field targets.

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December 2020 – Signed a Memorandum of Understanding (MoU) with Saipem for a collaboration in decarbonization projects in Italy focused on capture, transport, reuse, and storage of CO2 produced by the industrial activity.

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December 2020 – Signed a Sale and Purchase agreement for the acquisition from Equinor and SSE Renewables of a 20% interest in the Dogger Bank (A and B) offshore wind projects in the UK, which will be the largest wind power facility in the world, with a planned installed capacity of 2.4 GW (100% share), with completion expected in 2023-2024. The operation will contribute 480 MW to the renewable generation capacity and to Eni’s growth targets.

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December 2020 – Signed an agreement with Enel aimed at the study and development of green hydrogen projects, through facilities powered by renewable energy.

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November 2020 – Versalis signed an agreement with AlphaBio Control, a research and development company engaged in the production of natural formulations for the protection of crops, aimed at the production of herbicides and biocides for the disinfection of plant-based and biodegradable surfaces, using the active ingredients produced from the chemistry from the renewable sources platform of Porto Torres.

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November 2020 – Agreement between Eni Rewind and Herambiente for the construction in Ravenna in the decommissioned industrial area “Ponticelle”, a platform for the treatment of non-recyclable industrial waste able to manage up to 60 ktonnes/year, coherently with circular economy principles.

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November 2020 – Achieved the first allowance of carbon credits by the REDD+ Luangwa Community Forest Project (LCFP) to offset GHG emissions equivalent to 1.5 million tonnes of CO2.

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November 2020 – Versalis signed an agreement with AGR, an Italian company that owns a proprietary technology to treat used elastomers, to develop and market new products and applications in recycled rubber, in collaboration with the EcoTyre Consortium, which manages a national network for the collection and processing of ELTs (End-of-Life Tyres).

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November 2020 – Within the partnership with Falck Renewables, Eni acquired a 30 MW solar project “ready to build” in Virginia from Savion LLC (14.5 MW in Eni share). The plant will avoid over 33 ktonnes of CO2 emissions per year.

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November 2020 – Eni Research Center for Renewable Energy and the Environment in Novara launched a pilot trial for a technology for the capture/reuse of CO2 (CCU) based on bio-fixation through micro-algae, with the production of an algal oil usable in bio-refineries.

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October 2020 – Awarded by the UK Oil and Gas Authority a license for building a carbon storage project in depleted offshore fields located in the Liverpool Bay and the Irish Sea. The project includes the reutilization and refurbishment of Eni’s depleted fields with a target of storing 3 million tonnes per year of CO2. Activity start-up is expected in 2025. Eni is expected to coordinate the storage and transportation phase from existing industries and future hydrogen production sites in the area, within the HyNet North West integrated project.

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September 2020 – Made a gas discovery in the Abu Madi West (Eni operator with a 75% interest) concession in the Great Nooros Area in the Nile Delta. The preliminary evaluation of the well results, considering the extension of the reservoir towards north and the dynamic behaviour of the field, together with the recent discoveries performed in the area, indicates that the Great Nooros Area gas in place can be estimated in excess of 4 Tcf.

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August 2020 – Signed through the subsidiary Novis Renewables Holdings (Eni’s interest 49%), an

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agreement with Building Energy SpA to acquire Building Energy Holdings US (BEHUS) managing 62 MW of wind and solar capacity fully in operation in the U.S.A. and a pipeline of wind projects of up to 160 MW. Production from already in operation BEHUS assets is expected to avoid over 93 ktons of CO2/y.

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August 2020 – Versalis signed an agreement with Forever S.p.A., a leading Italian company in the recovery and recycling of post-consumer plastic to develop and market a new range of solid polystyrene products made from recycled packaging.

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July 2020 – Eni have successfully drilled the first exploration well in the North El Hammad license, in the Bashrush prospect in the Nile Delta, located near Nooros and Baltim South West fields. The well has been opened to test potentiality of production, and it delivered up to 32 mmcf/d of gas. The test rate was limited by surface testing facilities. The well deliverability in production configuration is estimated at up to 100 mmcf of gas and 800 barrels of condensate per day.

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July 2020 – Made an oil discovery in the SWM-A-6X exploration prospect, in South West Meleiha concession, in the Western Desert of Egypt. Production from South West Meleiha concession, started up in July 2019, in just one year ramped up to 12,000 BOE/d leveraging on the contribution of new discoveries.

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July 2020 – Eni confirms and expands gas and condensate potential in the Ken Bau discovery in Block 114, offshore Vietnam. The estimate of gas and condensate potential was increased to 7-9 trillion cubic feet of gas in place and 400-500 million of barrels of condensate.

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July 2020 – Versalis finalized the acquisition of a 40% interest in Finproject, a company engaged in the high-performance polymers segment, increasing exposure to products more resilient to the volatility of the chemical scenario.

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July 2020 – Made a gas discovery in the license of North El Hammad, in the Bashrush prospect in the Nile Delta, located near Nooros and Baltim South West fields. The new discovery is located in 22 meters of water depth, 11 km from the coast and 12 km North-West from the Nooros field and about 1 km west of the Baltim South West field, both already in production.

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July 2020 – Launched a strategic partnership between Eni gas e luce and OVO targeting the residential market in France to raise customer awareness for a responsible use of energy and access to zero-emission technologies leveraging digitalization.

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July 2020 – Started a photovoltaic plant at the Volpiano site in Italy (total capacity of 18 MW) with an expected production of 27 GWh/y, avoiding 370 ktonnes of CO2 emissions over the service life of the plant.

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June 2020 – Versalis signed an agreement with COREPLA (National Consortium for the Collection, Recycling and Recovery of Plastic Packaging) to develop effective solutions to reutilize plastics, applying Eni’s expertise in the fields of gasification and chemical recycling by means of pyrolysis.

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June 2020 – Acquired a 20% interest in Tate s.r.l., a start-up operating in the activation and management of electricity and gas contracts through digital solutions.

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June 2020 – Acquired from Asja Ambiente three wind projects for a total capacity of 35.2 MW, which are expected to produce approximately 90 GWh/y, avoiding around 38,000 tonnes of CO2 emissions per year. The three plants, currently under construction, are the first wind project to be launched by Eni in Italy.

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March 2020 – Completed the construction of a gas pipeline connecting Bir Rebaa Nord (BRN) and Menzel Ledjmet Est (MLE) fields in the Berkine Basin, in the south-eastern part of Algeria. When fully operational, the gas project of the Berkine Nord will bring production to a total of 6.5 million cubic meters and 10,000 barrels of associated liquids which, together with the oil development, will lead to an overall production of 65,000 barrels of oil equivalent per day (boed) by 2020.

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March 2020 – Started up a wind farm in Kazakhstan with a capacity of 48 MW.

For significant business and portfolio developments occurred from January 2020 to the beginning of March 2020 see also the Annual Report on Form 20-F 2019 filed to SEC on April 2, 2020.

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BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in forty-two countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and the United Arab Emirates. In 2020, Eni average daily production amounted to 1,609 KBOE/d on an available-for-sale basis. As of December 31, 2020, Eni’s total proved reserves amounted to 6,905 mmBOE; proved reserves of subsidiaries totaled 5,984 mmBOE; Eni’s share of reserves of equity-accounted entities was 921 mmBOE.

“Eni’s strategy and short-to-medium term targets in its Exploration & Production segment are disclosed in Item 5 – Business trends and Management’s expectations of operations.”

Disclosure of reserves

Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable 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 under 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.

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 rules1. 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.

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

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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.

The head of the Reserves Department attended the “Politecnico di Torino” and received a Master of Science degree in Mining Engineering in 2000. He was appointed in 2020 and has more than 20 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfil the professional qualifications requested by the role and comply 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 companies2. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report3. 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. In 2020, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 36% of Eni’s total proved reserves at December 31, 20204, confirming, as in previous years, the reasonableness of Eni internal evaluation5.

In the 2018-2020 three-year period, 92% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2020, Balder in Norway and Merakes in Indonesia were the main Eni property, which did not undergo an independent evaluation in the last three years.

From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott. In 2018, the Societé Generale de Surveillance (SGS) company also provided an independent certification.

See “Item 19 – Exhibits”.

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

See “Item 19 – Exhibits”.

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Summary of proved oil and gas reserves

The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2020, 2019 and 2018.

HYDROCARBONS(1) (mmBOE)	Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total reserves
Consolidated subsidiaries(2)
Dec. 31, 2020	243	73	798	1,110	1,352	1,182	879	256	91	5,984
developed	199	68	434	1,022	799	1,093	424	162	60	4,261
undeveloped	44	5	364	88	553	89	455	94	31	1,723
Dec. 31, 2019	333	89	974	1,225	1,453	1,108	742	268	95	6,287
developed	258	82	553	1,033	863	1,046	372	182	61	4,450
undeveloped	75	7	421	192	590	62	370	86	34	1,837
Dec. 31, 2018	428	106	1,022	1,246	1,361	1,066	700	302	125	6,356
developed	336	99	582	764	895	925	403	170	87	4,261
undeveloped	92	7	440	482	466	141	297	132	38	2,095
Equity-accounted entities(3)
Dec. 31, 2020		496	14		87			324		921
developed		254	14		47			324		639
undeveloped		242			40					282
Dec. 31, 2019		567	16		63			335		981
developed		330	16		23			335		704
undeveloped		237			40					277
Dec. 31, 2018		363	14		68			352		797
developed		205	14		17			347		583
undeveloped		158			51			5		214
Consolidated subsidiaries and equity accounted entities
Dec. 31, 2020	243	569	812	1,110	1,439	1,182	879	580	91	6,905
developed	199	322	448	1,022	846	1,093	424	486	60	4,900
undeveloped	44	247	364	88	593	89	455	94	31	2,005
Dec. 31, 2019	333	656	990	1,225	1,516	1,108	742	603	95	7,268
developed	258	412	569	1,033	886	1,046	372	517	61	5,154
undeveloped	75	244	421	192	630	62	370	86	34	2,114
Dec. 31, 2018	428	469	1,036	1,246	1,429	1,066	700	654	125	7,153
developed	336	304	596	764	912	925	403	517	87	4,844
undeveloped	92	165	440	482	517	141	297	137	38	2,309

(1)

Effective January 1, 2020, Eni has updated the conversion rate of gas produced to 5,310 cubic feet of gas equals 1 barrel of oil (it was 5,408 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, 2020 amounted to 67 mmBOE. Prior-year converted amounts were left unchanged.

(2)

Include Eni’s share of reserves held by a joint-operation in Mozambique which is proportionally consolidated in the Group consolidated financial statements in accordance to IFRS.

(3)

Reserves volumes of the Rest of Europe area, in 2018, are affected by the merger agreement that provided for the sale of the reserves of the former subsidiary Eni Norge as part of the business combination with Point Resources and the acquisition of Eni’s share of the reserves held by the combined company Vår Energi, an equity-accounted entity participated by Eni with a 69.85% interest.

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LIQUIDS (mmBBL)	Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total reserves
Consolidated subsidiaries
Dec. 31, 2020	178	34	383	227	624	805	579	224	1	3,055
developed	146	31	243	172	469	716	297	143	1	2,218
undeveloped	32	3	140	55	155	89	282	81		837
Dec. 31, 2019	194	41	468	264	694	746	491	225	1	3,124
developed	137	37	301	149	519	682	245	148	1	2,219
undeveloped	57	4	167	115	175	64	246	77		905
Dec. 31, 2018	208	48	493	279	718	704	476	252	5	3,183
developed	156	44	317	153	551	587	252	143	5	2,208
undeveloped	52	4	176	126	167	117	224	109		975
Equity-accounted entities(1)
Dec. 31, 2020		400	12		18			30		460
developed		176	12		15			30		233
undeveloped		224			3					227
Dec. 31, 2019		424	12		10			31		477
developed		219	12		7			31		269
undeveloped		205			3					208
Dec. 31, 2018		297	11		12			37		357
developed		154	11		8			32		205
undeveloped		143			4			5		152
Consolidated subsidiaries and equity accounted entities
Dec. 31, 2020	178	434	395	227	642	805	579	254	1	3,515
developed	146	207	255	172	484	716	297	173	1	2,451
undeveloped	32	227	140	55	158	89	282	81		1,064
Dec. 31, 2019	194	465	480	264	704	746	491	256	1	3,601
developed	137	256	313	149	526	682	245	179	1	2,488
undeveloped	57	209	167	115	178	64	246	77		1,113
Dec. 31, 2018	208	345	504	279	730	704	476	289	5	3,540
developed	156	198	328	153	559	587	252	175	5	2,413
undeveloped	52	147	176	126	171	117	224	114		1,127

(1)

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NATURAL GAS (BCF)	Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total reserves
Consolidated subsidiaries(1)
Dec. 31, 2020	348	208	2,201	4,692	3,864	2,003	1,589	175	474	15,554
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
Dec. 31, 2019	752	262	2,738	5,191	4,103	1,969	1,349	240	507	17,111
developed	657	242	1,374	4,777	1,858	1,969	685	186	322	12,070
undeveloped	95	20	1,364	414	2,245		664	54	185	5,041
Dec. 31, 2018	1,199	320	2,890	5,275	3,506	1,989	1,217	277	651	17,324
developed	980	300	1,447	3,331	1,871	1,846	822	154	452	11,203
undeveloped	219	20	1,443	1,944	1,635	143	395	123	199	6,121
Equity-accounted entities(2)
Dec. 31, 2020		510	14		364			1,559		2,447
developed		415	14		170			1,559		2,158
undeveloped		95			194					289
Dec. 31, 2019		772	14		287			1,648		2,721
developed		597	14		88			1,648		2,347
undeveloped		175			199					374
Dec. 31, 2018		360	14		310			1,716		2,400
developed		276	14		57			1,716		2,063
undeveloped		84			253					337
Consolidated subsidiaries and equity accounted entities
Dec. 31, 2020	348	718	2,215	4,692	4,228	2,003	1,589	1,734	474	18,001
developed	280	609	1,028	4,511	1,921	2,003	674	1,668	315	13,009
undeveloped	68	109	1,187	181	2,307		915	66	159	4,992
Dec. 31, 2019	752	1,034	2,752	5,191	4,390	1,969	1,349	1,888	507	19,832
developed	657	839	1,388	4,777	1,946	1,969	685	1,834	322	14,417
undeveloped	95	195	1,364	414	2,444		664	54	185	5,415
Dec. 31, 2018	1,199	680	2,904	5,275	3,816	1,989	1,217	1,993	651	19,724
developed	980	576	1,461	3,331	1,928	1,846	822	1,870	452	13,266
undeveloped	219	104	1,443	1,944	1,888	143	395	123	199	6,458

(1)

Include Eni’s share of reserves held by a joint-operation in Mozambique which is proportionally consolidated in the Group consolidated financial statements in accordance to IFRS.

(2)

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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 80 mmBOE as of December 31, 2020 (128 and 148 mmBOE as of December 31, 2019 and 2018, respectively). Said volumes are not included in reserves volumes shown in the table herein.

	Subsidiaries						Equity-accounted entities
(mmBOE)	2020		2019(a)		2018		2020		2019		2018
Revisions of previous estimates		216		459		590		3		62		(99)
Improved recovery		5				13
Extensions and discoveries		17		101		169		30		6
Purchases of minerals-in-place				30		332				184		363
Sales of minerals-in-place				(42)		(528)				(6)		(1)
Total additions to proved reserves		238		548		576		33		246		263
Production for the year(b)		(541)		(617)		(650)		(93)		(62)		(26)

(a)

Sales of minerals-in-place include approximately 4 million boe of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms.

(b)

The difference compared to production sold of 575.2 mmBOE (625.0 mmBOE in 2018 and 630.6 mmBOE in 2019) reflected hydrocarbons volumes of 45.4 mmBOE consumed in operations (43.5 mmBOE in 2018 and 45.4 mmBOE in 2019), changes in inventories and other factors.

	Subsidiaries and equity-accounted entities
(%)	2020		2019		2018
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources		43		117		124
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic		43		92		100

Eni’s proved reserves as of December 31, 2020 totaled 6,905 mmBOE (liquids 3,515 mmBBL; natural gas 18,001 BCF) and included the effect of an updating of the gas conversion factor (up by 67 mmBOE). Eni’s proved reserves reported a decrease of 363 mmBOE, or 5%, from December 31, 2019, as they were negatively affected by a depressed scenario with the crude oil prices decreased to historic lows due to disruptive effects of the COVID-19 pandemic crisis, which forced us to reduce development expenditures to preserve the Company’s cash flows.

Lower prices limit the amount of proved reserves that we can produce economically, thus adversely affecting our proved reserves volumes and the reserve replacement ratio as well as accelerating the reduction in our existing reserve levels as we continue production from our fields.

All sources additions to proved reserves booked in 2020 were 271 mmBOE; of which 238 mmBOE came from Eni’s subsidiaries, while 33 mmBOE from Eni’s equity-accounted entities.

The overall effect of price variations was negligible and estimated to be negative for 6 mmBOE in 2020 (of which a net positive revision of 18 mmBOE recorded at Eni’s subsidiaries and a net negative revision of 24 mmBOE recorded at Eni’s equity-accounted entities). However, there were two significant offsetting factors. First, due to a depressed oil price environment the Brent reference price used in the reserve estimation process was calculated at 41 $/barrel in 2020, much lower than the 63 $/barrel used in 2019, leading us to reduce our proved reserves by 124 mmBOE, due to the removal of volumes of reserves which have become uneconomical in this environment. There was also an offsetting positive addition due to net higher reserves entitlements under our PSA contracts of 118 mmBOE because of the cost recovery mechanism. Further information about how to determine year-end amounts of proved reserves and the relevant net present value is provided in “Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas”. The methods (or technologies) used in the Eni’s proved reserves assessment in 2020 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

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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 43% in 2020 (117% in 2019 and 124% in 2018). The organic reserves replacement ratio was 43% in 2020 (92% in 2019 and 100% in 2018) which excluded sales and purchases of minerals-in-place.

The all sources reserve replacement ratio during the three years ended December 31, 2020, which included a net increase of 332 mmBOE related to sales and purchases, was 96%.

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 – Risks associated with the exploration and production of oil and natural gas – Uncertainties in estimates of oil and natural gas reserves”.

The average reserves life index of Eni’s proved reserves was 10.9 years as of December 31, 2020, which included reserves of both subsidiaries and equity-accounted entities.

Eni’s subsidiaries

Eni’s subsidiaries added 238 mmBOE of proved oil and gas reserves in 2020 and included the impact of the gas conversion factor update (58 mmBOE). Additions comprised an increase of 194 mmBBL and a decrease of 73 BCF. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates were overall positive for 216 mmBOE and mainly derived from the progress in development activities at several fields, including Zubair in Iraq, Kashagan and Karachaganak in Kazakhstan as well as Merakes in Indonesia. Revisions also included net positive price effects of 18 mmBOE described above; (ii) extensions and discoveries were up by 17 mmBOE mainly due to the final investment decisions made for the projects of Mahani in the onshore United Arab Emirates. This field started up in January 2021; and (iii) improved recovery of 5 mmBOE related to the Burun field in Turkmenistan.

Further information and explanations of significant changes with respect to each line item of the movements in net proved reserves are provided in Supplemental oil and gas information on page F-150 and subsequent pages.

Eni’s share of equity-accounted entities

Eni’s share of equity-accounted entities added 33 mmBOE of proved oil and gas reserves in 2020 and included the impact of the gas conversion factor update (9 mmBOE). The breakdown of total additions to proved reserves is the following: (i) extensions and discoveries were up by 30 mmBOE mainly due to the final investment decisions made for the projects of Bredaiblikk in Norway; (ii) revisions of previous estimates were up by 3 mmBOE mainly due to the progress in development activities at the Angola-LNG project (up by 30 mmBOE), partly offset by negative price effects of 24 mmBOE, mainly recorded in Norway, and minor negative revisions for 3 mmBOE.

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2020 totaled 2,005 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,064 mmBBL, mainly concentrated in Africa and Asia.

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Proved undeveloped reserves of natural gas amounted to 4,992 BCF, mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 837 mmBBL of liquids and 4,703 BCF of natural gas. The table below provides a summary of changes in total proved undeveloped reserves for 2020.

Subsidiaries and equity-accounted entities (mmBOE)	2020
Proved undeveloped reserves as of December 31, 2019		2,114
Transfers to proved developed reserves		(206)
Extensions and discoveries		40
Revisions of previous estimates		53
Improved recovery		4
Proved undeveloped reserves as of December 31, 2020		2,005

During 2020, Eni matured 206 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: Zohr in Egypt, Zubair in Iraq, Area 1 in Mexico, Umm Shaif/Nasr in the United Arab Emirates and Karachaganak in Kazakhstan.

For further information see also Supplemental oil and gas information on page F-150 and subsequent pages.

In 2020, capital expenditure amounted to approximately €4.2 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 0.5 BBOE of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date and unchanged from 2019. The proved undeveloped reserves that have remained undeveloped for five years or more at the balance sheet date mainly related to: (i) the Zubair field in Iraq (0.15 BBOE), where development of PUDs has been conditioned by the drilling of additional production and injection wells to be linked to the production facilities, which were already completed to achieve the full field production plateau of 700 KBBL/d; (ii) certain Libyan gas fields (0.25 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; in order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields, which are expected to be put in production over the next several years; and (iii) other fields in Italy and Egypt (0.1 BBOE) where development activities are in progress. (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

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 623 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

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reserves and supplies from third parties based on existing contracts. Production is expected to account for approximately 93% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2020.

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 2020, oil and natural gas production available for sale averaged 1,609 KBOE/d (1,736 KBOE/d in 2019). Production for the year expressed in barrel-of-oil equivalent was calculated assuming a natural gas conversion factor which was updated to 5,310 CF of gas equaling 1 barrel of oil without restating the comparative periods (it was 5,408 cubic feet of gas per barrel in previous reporting periods. For further information see “Item 3 – Selected operating information”). On a comparable basis, i.e. when excluding the effect of updating the gas conversion factor, production decreased by 8% from 2019.

Production reported in 2020 was negatively affected by the COVID-19 impacts on the global hydrocarbons demands and on the Company’s cash flows. Our production volumes were reduced as a consequence of a reduction in capital expenditures to develop reserves, OPEC+ mandated production cuts and a slowdown in gas demand, mainly in Egypt. The new production from start-up and ramp-up equal to 109 KBOE/d, the net positive price effects of 12 KBOE/d and the portfolio contributions in Norway were partially offset by lower volumes reported in Libya since during the year a contractual parameter already envisaged in the contract has been triggered and will be applied going forward, lower entitlements/spending and losses due to force majeure, and finally by mature fields declines.

Liquids production (841 KBBL/d) decreased by 49 KBBL/d, or approximately 5% from the full year of 2019. The reduction in Libya, the effects of capex and OPEC+ cuts, as well as mature field declines were partially offset by the contribution of portfolio activities and production growth in Mexico due to the ramp-up of Area 1, Angola for the start-up of Agogo, Congo due to the Nenè phase 2B start-up, Algeria and Kazakhstan.

Natural gas production (4,077 mmCF/d) decreased by 499 mmCF/d, or approximately 11% compared to the full year of 2019. Lower production in Libya and the impact of lower natural gas demand in certain areas (mainly in Egypt), as well as lower LNG demand were partly offset by the growth in Algeria due to the start-up of the Berkine gas project and in Kazakhstan.

Sales volumes of oil and gas production sold were 575.2 mmBOE. The 13.7 mmBOE difference over production on available-for-sale basis (588.9 mmBOE in 2020) reflected mainly changes in inventory and other factors. Approximately 67% of liquids production sold (300.1 mmBBL) was destined to Eni’s Refining & Marketing business. About 19% of natural gas production sold (1,461 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.

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Average daily production available for sale(a)

	2020(b)			2019(c)			2018
	Liquids (KBBL/d)	Natural gas (mmCF/d)	Hydrocarbons (KBOE/d)	Liquids (KBBL/d)	Natural gas (mmCF/d)	Hydrocarbons (KBOE/d)	Liquids (KBBL/d)	Natural gas (mmCF/d)	Hydrocarbons (KBOE/d)
Eni consolidated subsidiaries
Italy	47	279	100	53	338	116	60	386	130
Rest of Europe	23	143	50	23	158	52	113	410	188
Croatia								10	2
Norway							89	225	131
United Kingdom	23	143	50	23	158	52	24	175	55
North Africa	111	638	231	166	1,023	356	154	1,188	372
Algeria	53	67	65	62	33	69	65	35	72
Libya	55	561	161	101	980	282	86	1,141	295
Tunisia	3	10	5	3	10	5	3	12	5
Egypt	64	1,123	275	75	1,425	338	77	1,147	287
Sub-Saharan Africa	218	539	320	247	415	324	244	346	308
Angola	89		89	101		101	111		111
Congo	49	89	66	59	93	77	65	104	84
Ghana	24	80	40	23	42	30	15	9	17
Nigeria	56	370	125	64	280	116	53	233	96
Kazakhstan	109	247	156	99	240	143	91	228	133
Rest of Asia	88	326	149	85	350	150	77	412	152
China	1		1	1		1	1		1
Indonesia	1	208	40	2	255	49	3	315	60
Iraq	31		31	26		26	28		28
Pakistan		69	13		92	17		97	18
Timor Leste	2	45	10
Turkmenistan	7		7	7		7	6		6
United Arab Emirates	46	4	47	49	3	50	39		39
Americas	57	58	68	56	48	64	52	108	72
Ecuador				6		6	12		12
Mexico	12	10	14	4	2	4
Trinidad & Tobago								36	6
United States	45	48	54	46	46	54	40	72	54
Australia and Oceania		88	17	2	134	27	2	110	22
Australia		88	17	2	134	27	2	110	22
	717	3,441	1,366	806	4,131	1,570	870	4,335	1,664
Eni share of equity-accounted entities
Angola	4	87	20	4	86	20	3	75	17
Indonesia								2	1
Norway	116	338	180	74	168	105
Tunisia	2	1	2	3		3	3	2	3
Venezuela	2	210	41	3	191	38	8	216	47
	124	636	243	84	445	166	14	295	68
Total	841	4,077	1,609	890	4,576	1,736	884	4,630	1,732

(a)

It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 124, 124 and 119 KBOE/d in 2020, 2019 and 2018, respectively.

(b)

Effective January 1, 2020, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,310 cubic feet of gas (it was 1 barrel of oil = 5,408 cubic feet of gas). The effect of this update on production expressed in boe was approximately 14 KBOE/d for the full year 2020. Prior-year converted amounts were left unchanged.

(c)

Daily production for the year excludes approximately 10 KBOE/d of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. Such volume is classified as sales of minerals-in-place within the reserves movements for the year.

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Annual production available for sale(a)

	2020(b)			2019(c)			2018
	Liquids (mmBBL)	Natural gas (BCF)	Hydrocarbons (mmBOE)	Liquids (mmBBL)	Natural gas (BCF)	Hydrocarbons (mmBOE)	Liquids (mmBBL)	Natural gas (BCF)	Hydrocarbons (mmBOE)
Eni consolidated subsidiaries
Italy	17	102	36	19	123	42	22	141	48
Rest of Europe	8	52	18	8	58	19	41	150	68
Croatia								4	1
Norway							33	82	47
United Kingdom	8	52	18	8	58	19	8	64	20
North Africa	41	234	85	61	374	130	56	434	136
Algeria	19	25	24	23	12	25	24	13	26
Libya	21	205	59	37	358	103	31	417	108
Tunisia	1	4	2	1	4	2	1	4	2
Egypt	24	411	101	27	520	123	28	419	105
Sub-Saharan Africa	80	198	117	90	152	118	89	126	112
Angola	33		33	37		37	41		41
Congo	18	33	24	22	34	28	24	38	30
Ghana	9	29	14	8	16	11	5	3	6
Nigeria	20	136	46	23	102	42	19	85	35
Kazakhstan	40	90	57	36	87	52	34	83	49
Rest of Asia	32	119	55	32	127	56	28	150	55
China				1		1	1		1
Indonesia		76	15		93	18	1	115	22
Iraq	11		11	10		10	10		10
Pakistan		25	5		33	6		35	6
Timor Leste	1	16	4
Turkmenistan	3		3	3		3	2		2
United Arab Emirates	17	2	17	18	1	18	14		14
Americas	21	21	25	20	18	23	19	40	26
Ecuador				2		2	4		4
Mexico	4	4	5	1	1	1
Trinidad & Tobago								13	2
United States	17	17	20	17	17	20	15	27	20
Australia and Oceania		32	6	1	49	10	1	40	8
Australia		32	6	1	49	10	1	40	8
	263	1,259	500	294	1,508	573	318	1,583	607
Eni share of equity-accounted entities
Angola	1	32	7	2	31	7	1	27	6
Indonesia
Norway	42	124	66	27	61	39
Tunisia	1		1	1		1	1	1	1
Venezuela	1	77	15	1	70	14	3	79	18
	45	233	89	31	162	61	5	107	25
Total	308	1,492	589	325	1,670	634	323	1,690	632

(a)

It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 45.4, 45.4 and 43.5 mmBOE in 2020, 2019 and 2018, respectively.

(b)

Effective January 1, 2020, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,310 cubic feet of gas (it was 1 barrel of oil = 5,408 cubic feet of gas). The effect of this update on production expressed in boe was approximately 5 mmBOE for the full year 2020. Prior-year converted amounts were left unchanged.

(c)

Production for the year excludes approximately 4 mmBOE of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. Such volume is classified as sales of minerals-in-place within the reserves movements for the year.

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Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 60 KBOE/d, 71 KBOE/d and 54 KBOE/d in 2020, 2019 and 2018, 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.

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($)	Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2018
Consolidated subsidiaries
Oil and condensates, per BBL	61.58	64.51	65.95	62.97	68.76	66.78	68.35	57.22	68.72	65.79
Natural gas, per KCF	8.37	7.99	4.97	4.85	2.38	0.77	6.11	2.38	4.80	5.17
Total hydrocarbons, per BOE	53.01	56.07	43.34	36.22	58.59	46.98	50.98	46.63	28.99	48.04
Average production cost, per BOE	9.97	8.39	3.16	3.87	10.25	6.53	4.68	10.56	7.09	6.50
Equity-accounted entities
Oil and condensates, per BBL			17.92		39.48		49.86	54.86		45.19
Natural gas, per KCF			3.58		9.50		9.32	4.28		5.59
Total hydrocarbons, per BOE			18.14		48.79		50.64	28.59		33.63
Average production cost, per BOE			6.84		6.53		11.03	2.47		3.76
2019
Consolidated subsidiaries
Oil and condensates, per BBL	55.55	58.92	57.91	54.78	63.45	59.06	62.81	54.00	52.93	59.62
Natural gas, per KCF	5.03	4.95	6.21	5.11	2.94	0.81	5.94	2.46	4.41	4.94
Total hydrocarbons, per BOE	40.24	39.84	44.86	33.67	53.08	42.21	50.31	48.37	26.32	43.73
Average production cost, per BOE	10.38	10.71	4.48	2.99	8.02	5.46	5.20	13.07	4.83	6.05
Equity-accounted entities
Oil and condensates, per BBL		58.88	18.06		23.72			59.94		55.93
Natural gas, per KCF		5.07	7.23		6.16			4.32		4.94
Total hydrocarbons, per BOE		49.76	19.39		30.84			25.67		41.71
Average production cost, per BOE		9.78	8.51		3.68			2.04		7.26
2020
Consolidated subsidiaries
Oil and condensates, per BBL	34.58	32.82	38.33	36.66	39.99	37.37	37.69	33.03	17.45	37.56
Natural gas, per KCF	3.16	3.12	4.33	4.78	2.76	0.69	4.09	2.10	3.84	3.77
Total hydrocarbons, per BOE	25.28	23.94	30.28	28.03	32.06	27.22	31.31	29.57	20.35	29.20
Average production cost, per BOE	10.41	8.76	4.99	4.15	7.63	4.94	4.92	12.54	3.10	6.31
Equity-accounted entities
Oil and condensates, per BBL		35.23	18.16		17.13			27.20		34.21
Natural gas, per KCF		3.25	6.29		3.94			4.37		3.73
Total hydrocarbons, per BOE		29.17	19.36		19.97			23.39		27.33
Average production cost, per BOE		6.07	9.97		3.56			1.37		5.10

Development well activity

In 2020, a total of 182 development wells were drilled (57.4 of which represented Eni’s share) as compared to 241 development wells drilled in 2019 (85.4 of which represented Eni’s share) and 209 development wells drilled in 2018 (80.2 of which represented Eni’s share).

The drilling of 58 development wells (14.2 of which represented Eni’s share) is currently underway.

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The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2020. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

	Net wells completed						Wells in progress at 31 Dec.
	2020		2019		2018		2020
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy			3.0		3.0
Rest of Europe	2.8		3.3		2.8	0.3	24.0	5.0
North Africa	4.3		5.0	1.1	9.6	0.5	3.0	1.5
Egypt	23.2		33.5		30.7		3.0	1.4
Sub-Saharan Africa	1.2		7.0		7.3	0.1	5.0	0.9
Kazakhstan	0.3		0.9		0.9
Rest of Asia	23.2	0.4	27.3	2.2	21.9		17.0	3.4
Americas	2.0		2.1		2.3		6.0	2.0
Australia and Oceania					0.8
Total including equity-accounted entities	57.0	0.4	82.1	3.3	79.3	0.9	58.0	14.2

Exploration well activity

In 2020, a total of 28 new exploratory wells were drilled (13.8 of which represented Eni’s share), as compared to 31 exploratory wells drilled in 2019 (16.3 of which represented Eni’s share) and 24 exploratory wells drilled in 2018 (15.6 of which represented Eni’s share).

The overall commercial success rate was 28% (30% net to Eni) as compared to 36% (47% net to Eni) and 62% (66% net to Eni) in 2019 and 2018, 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, 2020. 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 note 11 on Consolidated Financial Statements.

	Net wells completed						Wells in progress at Dec. 31
	2020		2019		2018		2020
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy				0.5	1.8
Rest of Europe	0.8	0.4	0.3	1.4		0.5	16.0	3.3
North Africa	0.5	1.5	0.5			0.5	9.0	7.5
Egypt	0.7	1.5	4.5	1.5	1.7	1.5	15.0	11.8
Sub-Saharan Africa	0.1	0.9	0.5	0.9	0.4		33.0	17.8
Kazakhstan		1.1
Rest of Asia	0.8	0.9		1.7	2.2	2.6	11.0	4.5
Americas		0.6			4.0		1.0	0.8
Australia and Oceania				0.5			1.0	0.3
Total including equity-accounted entities	2.9	6.9	5.8	6.5	10.1	5.1	86.0	46.0

Oil and gas properties, operations and acreage

In 2020, Eni performed its operations in forty-two Countries located in five continents. As of December 31, 2020, Eni’s mineral right portfolio consisted of 798 exclusive or shared rights of exploration and development activities for a total acreage of 336,449 square kilometers net to Eni (357,854 square kilometers net to Eni as of December 31, 2019). Developed acreage was 26,359 square kilometers and undeveloped acreage was 310,090 square kilometers net to Eni.

In 2020 new leases were purchased or awarded in Albania, Oman, the United Arab Emirates, Angola, Indonesia, Norway and Egypt for a total increase in acreage of approximately 23,600 square kilometers. Interest increases were reported mainly in Myanmar and Australia for a total acreage of approximately 4,800 square kilometers. Relinquishment for the year related mainly to Somalia, Myanmar, Indonesia, Pakistan and Gabon covering an acreage of approximately 47,500 square kilometers. Partial relinquishment was reported mainly in Algeria, Cyprus and Egypt for approximately 2,300 square kilometers.

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Eni’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions under which the Company maintains exploration and/or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Eni may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, Eni has generally been successful in obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Company.

The gross undeveloped acreages that will expire in the next three years are related to exploration leases, blocks, concessions in: (i) Rest of Asia, in particular in Oman, Russia, Vietnam and Myanmar; (ii) North Africa, in particular in Morocco and Libya; and (iii) Sub-Saharan Africa, in particular in Kenya, Mozambique and South Africa. In most cases extension or renewal options are contractually defined and may or may not be exercised in according 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, 2020. A gross acreage is one in which Eni owns a working interest.

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	December 31, 2019	December 31, 2020
	Total net acreage(a)	Number of interests	Gross developed acreag (a)(b)	Gross undeveloped acreage(a)	Total gross acreage(a)	Net developed acreage(a)(b)	Net undeveloped acreage(a)	Total net acreage(a)
EUROPE	38,028	312	15,284	63,741	79,025	9,335	30,506	39,841
Italy	13,732	129	9,578	7,220	16,798	7,951	5,681	13,632
Rest of Europe	24,296	183	5,706	56,521	62,227	1,384	24,825	26,209
Albania		1		587	587		587	587
Cyprus	14,557	7		25,474	25,474		13,988	13,988
Greenland	1,909	2		4,890	4,890		1,909	1,909
Montenegro	614	1		1,228	1,228		614	614
Norway	4,213	136	4,799	20,868	25,667	772	5,481	6,253
United Kingdom	1,120	34	907	773	1,680	612	363	975
Other Countries	1,883	2		2,701	2,701		1,883	1,883
AFRICA	163,625	255	48,458	232,341	280,799	12,333	116,834	129,167
North Africa	31,873	71	12,213	55,419	67,632	5,312	25,721	31,033
Algeria	5,572	49	6,742	3,982	10,724	2,818	1,914	4,732
Libya	13,294	11	1,963	24,673	26,636	958	12,336	13,294
Morocco	10,755	1		23,900	23,900		10,755	10,755
Tunisia	2,252	10	3,508	2,864	6,372	1,536	716	2,252
Egypt	7,613	57	5,638	14,984	20,622	2,109	5,275	7,384
Sub-Saharan Africa	124,139	127	30,607	161,938	192,545	4,912	85,838	90,750
Angola	3,744	47	8,158	13,146	21,304	1,035	4,604	5,639
Congo	1,471	21	1,164	1,320	2,484	678	628	1,306
Gabon	4,107	3		2,931	2,931		2,931	2,931
Ghana	579	3	226	930	1,156	100	395	495
Ivory Coast	3,724	4		3,747	3,747		3,372	3,372
Kenya	43,948	6		50,677	50,677		43,948	43,948
Mozambique	4,349	10		25,304	25,304		4,349	4,349
Nigeria	6,642	32	21,059	8,206	29,265	3,099	3,340	6,439
South Africa	22,271	1		55,677	55,677		22,271	22,271
Other Countries	33,304
ASIA	142,696	69	12,994	271,271	284,265	3,343	151,502	154,845
Kazakhstan	2,160	7	2,391	3,853	6,244	442	1,505	1,947
Rest of Asia	140,536	62	10,603	267,418	278,021	2,901	149,997	152,898
Bahrain	2,858	1		2,858	2,858		2,858	2,858
China	13	4	68		68	11		11
Indonesia	15,955	13	2,605	18,672	21,277	1,029	13,155	14,184
Iraq	446	1	1,074		1,074	446		446
Lebanon	1,461	2		3,653	3,653		1,461	1,461
Myanmar	14,147	3		13,750	13,750		10,015	10,015
Oman	49,918	3		102,016	102,016		58,955	58,955
Pakistan	3,779	13	3,442	2,443	5,885	886	1,427	2,313
Russia	17,975	2		53,930	53,930		17,975	17,975
Timor Leste	1,620	4		2,612	2,612		1,620	1,620
Turkmenistan	180	1	200		200	180		180
United Arab Emirates	10,387	10	3,214	28,976	32,190	349	18,331	18,680
Vietnam	18,553	4		23,908	23,908		20,956	20,956
Other Countries	3,244	1		14,600	14,600		3,244	3,244
AMERICAS	10,703	157	2,267	15,274	17,541	1,020	8,699	9,719
Mexico	3,106	10	14	5,455	5,469	14	3,092	3,106
United States	1,935	134	992	952	1,944	509	689	1,198
Venezuela	1,066	6	1,261	1,543	2,804	497	569	1,066
Other Countries	4,596	7		7,324	7,324		4,349	4,349
AUSTRALIA AND OCEANIA	2,802	5	328	3,180	3,508	328	2,549	2,877
Australia	2,802	5	328	3,180	3,508	328	2,549	2,877
Total	357,854	798	79,331	585,807	665,138	26,359	310,090	336,449

(a)

Square kilometers.

(b)

Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.

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The table below sets forth, as of December 31, 2020 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.


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 (45%), Giaurone (100%), Fiumetto (100%), Prezioso (100%) and Bronte (100%)
REST OF EUROPE
Norway(a)	(1965)	Operated	Goliat (45.40%), Marulk (13.97%), Balder & Ringhorne (62.87%) and Ringhorne East (48.88%)
		Non-operated	Åsgard (15.41%), Mikkel (33.79%), Great Ekofisk Area (8.65%), Snorre (12.96%), Ormen Lange (4.43%), Statfjord Unit (14.92%), Statfjord Satellites East (10.16%), Statfjord Satellites North (17.46%), Statfjord Satellites Sygna (14.67%) and Grane (19.78%)
United Kingdom	(1964)	Operated	Liverpool Bay (100%) and Hewett Area (89.3%)
		Non-operated	Elgin/Franklin (21.87%), Glenelg (8%), J Block (33%), Jasmine (33%) and Jade (7%)
NORTH AFRICA
Algeria(b)	(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 (55%), Block 403 (50%) and Block 405b (75%)
		Non-operated	Block 404 (12.25%) and Block 208 (12.25%)
Libya(b)	(1959)	Non-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%), Djebel Grouz (50%), MLD (50%) and El Borma (50%)
EGYPT(b)(c)	(1954)	Operated	Shorouk (Zohr – 50%), Nile Delta (Abu Madi West/Nidoco – 75%), Sinai (Belayim Land, Belayim Marine and Abu Rudeis – 100%), Meleiha (76%), North Port Said (Port Fouad – 100%), Temsah (Tuna, Temsah and Denise – 50%), Southwest Meleiha (100%), Baltim (50%), Ras Qattara (El Faras and Zarif – 75%), West Abu Gharadig (Raml – 45%) and West Razzak (100%)
		Non-operated	Ras el Barr (Ha’py and Seth — 50%) and South Ghara (25%)
SUB-SAHARAN AFRICA
Angola	(1980)	Operated	Blocco 15/06 (36.84%)
		Non-operated	Block 0 (9.8%), Development Areas in the Block 3 and 3/05-A (12%), Development Areas in the Block 14 (20%), Lianzi Development Area in the Block 14 K/A IMI (10%) and Development Areas in the Block 15 (18%)
Congo	(1968)	Operated	Nené Marine (65%), Litchendjili (65%), Zatchi (55.25%), Loango (42.5%), Ikalou (85%), Djambala (50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%), M’Boundi (83%) and Kouakouala (75%)
		Non-operated	Pointe-Noire Grand Fond (29.75%) and Likouala (35%)
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(d)	OML 118 (12.5%)
KAZAKHSTAN(b)	(1992)	Operated(e)	Karachaganak (29.25%)
		Non-operated	Kashagan (16.81%)
REST OF ASIA
Indonesia	(2001)	Operated	Jangkrik (55%)
Iraq	(2009)	Operated(f)	Zubair (41.56%)
Pakistan	(2000)	Operated	Bhit/Bhadra (40%) and Kadanwari (18.42%)
		Non-operated	Latif (33.3%), Zamzama (17.75%) and Sawan (23.7%)
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 (85%), Longhorn (75%), Devils Towers (75%) and Triton (75%)
			Alaska: Nikaitchuq (100%) and Oooguruk (100%)
		Non-operated	Gulf of Mexico: Europa (32%), Medusa (25%), Lucius (8.5%), K2 (13.4%), Frontrunner (37.5%) and Heidelberg (12.5%)
			Texas: Alliance area (27.5%)
Venezuela	(1998)	Non-operated	Perla (50%), Corocoro (26%) and Junin 5 (40%)

(a)

Assets held by the Var energy equity-accounted entities (Eni’s interest 69.85%).

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(b)

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.

(c)

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.

(d)

As partners of SPDC JV, Eni holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks.

(e)

Eni and Shell are co-operators.

(f)

Eni is leading a consortium of partners including international companies and the national oil company Missan Oil, a part of a technical service contract as a 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, 2020. 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 8,255 (2,806.9 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, 2020(a)

(units)	Oil Wells				Natural gas Wells
	Gross		Net		Gross		Net
Italy		205.0		159.2		396.0		341.6
Rest of Europe		633.0		109.5		183.0		48.6
North Africa		612.0		258.1		127.0		67.9
Egypt		1,233.0		527.3		144.0		44.3
Sub-Saharan Africa		2,589.0		524.8		194.0		24.1
Kazakhstan		207.0		56.7		1.0		0.3
Rest of Asia		1,012.0		369.5		180.0		60.8
Americas		253.0		130.6		284.0		81.6
Australia and Oceania						2.0		2.0
Total including equity-accounted entities		6,744.0		2,135.7		1,511.0		671.2

(a)

Multiple completion wells included above: approximateley 1,369 (349.0 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 production 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 as well as onshore permits in Pakistan. 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.

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- Eni operates under Production Sharing Agreements (PSAs) in several of the 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. 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 similar in arrangements Algeria, Angola, China, Congo, Egypt, Indonesia, Libya, Mexico, Mozambico, Timor Leste in the JPDA area, Turkmenistan, certain assets in Nigeria, Kazakhstan and offshore assets in Pakistan. 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, mainland and offshore Sicily and the Po Valley. Eni operates 30 onshore and 58 offshore productive concessions. Exploration activities have been substantially abandoned in recent years. In 2020, Italy accounted for approximately 6% of Eni’s total worldwide production of oil and natural gas.

In 2020, 36% of Eni’s domestic production derived from fields in the Adriatic and Ionian Seas, 48% from the Central Southern Apennines and approximately 10% from Sicily.

In the Adriatic Sea, activities in 2020 mainly concerned maintenance and production optimization at offshore gas fields to recover the residual mineral potential. The decommissioning plan to plug&abandon non-productive wells and remove non-productive platforms progressed in the year in compliance with applicable Italian laws; a total of five offshore platforms are currently in the authorization process to be removed.

Yearly maintenance and production optimization activities were completed in the Val d’Agri concession.

Development activities of the Cassiopea gas operated project (Eni’s interest 60%) progressed offshore Sicily.

In Italy, a new law was enacted effective February 12, 2019, which requires Italian administrative bodies to adopt a plan intended to identify areas that are suitable for carrying out oil and gas activities. See “Risk Factors – Oil and gas activity may be subject to increasingly high levels of regulations throughout the world, which may impact our extraction activities and the recoverability of reserves”. Based on the review of all facts and circumstances and on the current knowledge of the matter, management does not expect any material impacts on the Group’s future results of operations and cash flow as well as on the volumes of booked reserves from the enactment of this law. Currently, forty-one concessions for hydrocarbon development and production have expired, including Val d’Agri which is the largest Italian concession of

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the Company. Applications have been timely filed with Italian administrative Authority to obtain concessions’ renewals. The adoption of the above-mentioned plan is not expected to interfere with the administrative process of granting the renewals at the expired concessions.

Pending the administrative resolution, the current law provides for the prorogation of the concessions activities in accordance to the development plans agreed with the initial award.

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 where Eni has 69.85% participating interest.

In 2020, the Rest of Europe accounted for 14% of Eni’s total worldwide production of oil and natural gas.

Norway. Development activities mainly concerned: (i) the Johan Castberg sanctioned project (Eni’s interest 20.96%) with start-up expected in 2023; and (ii) the Balder X sanctioned project (Eni operator with a 62.87% interest) 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 FPSO unit that will be relocated in the area. Production start-up is expected in 2022.

In 2020, the Breidablikk project was sanctioned with start-up expected in 2024. The development activities include the drilling of 23 production wells that will be linked to existing facilities.

Exploration activity yielded positive results with: (i) the Tordis NE and Lomre oil discoveries in the PL089 block (Eni’s interest 11.24%); (ii) the Enniberg oil and and gas discovery in the 971 license (Eni’s interest 13.97%) in the North Sea, located near the Balder production field (Eni’s interest 62.87%); and (iii) in March 2021, new oil discovery in the PL532 license (Eni’s interest 21%) in the Barents Sea and in the PL 090/090I license (Eni’s interest 17%), located in the northern North Sea, respectively.

The mineral interest portfolio increases were as follows: (i) in 2020 seven exploration licenses were acquired as operator and ten licenses in partnership. The licenses are distributed over the three main sections of the Norwegian continental shelf; and (ii) in 2021 ten exploration licenses were awarded, of which two as operator in the North Sea and three as operator in the Barents Sea. The licenses are located near fields already in production or development.

United Kingdom. In January 2021, Eni was awarded a 100% interest in the exploration license P2511 in the North Sea.

North Africa

Eni’s operations in North Africa are mainly conducted in Algeria, Libya and Tunisia. In 2020, North Africa accounted for 15% of Eni’s total worldwide production of oil and natural gas.

Algeria. During the year, gas production was started at the Berkine North complex (Eni’s interest 49%) leveraging a fast-track development intended to valorize the existing gas reserves. The development program included the drilling of four producing wells that were linked to the existing facilities, as well as the laying of a pipeline connecting the producing field to the MLE treatment plant in Block 405b (Eni’s interest 75%). The upgrading of the MLE treatment plant was completed in the year and is expected to reach a gross peak production of 60 KBOE/d leveraging also the production of the Block 403 (Eni’s interest 50%) and of the Berkine North area by the end of 2021.

Other development activities mainly concerned production optimization in the operated Blocks 403a/d and ROM Nord (Eni’s interest 35%), Blocks 401a/402a (Eni’s interest 55%), Block 403, Block 405b and Block 404 (Eni’s interest 12.25%).

Exploration activities yielded positive results with the BKNES-1 near-field oil discovery well in the Berkine North area.

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Libya. Currently, Libya represents approximately 10% of the Group’s total production. At the beginning of 2020 oil export terminals in the Eastern and Southern part of Libya were blocked halting

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most of the Country’s oil exports terminals and force majeure was declared at several Libyan production facilities. Production shutdowns also involved certain of the Company profit centers (the El-feel and the Bu-Attifel oilfields). However, despite this difficult framework, the Company’s largest assets in the Country have continued producing regularly. In late September 2020, the situation has begun improving thanks to a temporary agreement between the conflicting factions, on which basis the blockade was lifted at the main ports for exporting crude oil and production resumed at the main fields, revoking force majeure. Despite this, 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 Area C, in 2041 for Contract Area E, in 2042 for Contract Area A and B as well as in 2043 for Contract Area D production.

Tunisia. Development activities concerned the Baraka operated concession (Eni’s interest 49%) with the completion of drilling activities and production start-up of three productive wells.

Exploration activity yielded positive results with the Debech b-1 near-field oil and condensate discovery in the MLD concession (Eni’s interest 50%) and already achieved production start-up.

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Egypt

In 2020, Egypt accounted for 17% of Eni’s total worldwide production of oil and natural gas, the largest contributor to the Company overall production level.

In 2020 the award of the exploration block West Sherbean (Eni’s interest 50%) in the onshore Nile Delta was ratified.

In 2020 development activities concerned: (i) the drilling of infilling wells in the production fields located in the Sinai area (Eni operator with a 100% interest) and Meleiha Complex (Eni operator with a 76% interest); (ii) the development of near-field discoveries made in the year which were readily put into production in the Arcadia South, Meleiha (Eni’s interest 76%), South West Meleiha (Eni’s interest 100%); (iii) the development of Baltim SW program with 2 additional wells reaching a total of 4 gas producers; and (iv) maintenance activities and extensive asset integrity programs at the onshore and offshore facilities of the Sinai, Western Desert and Mediterranean assets.

In 2020, production at the Zohr field averaged approximately 131 KBOE/d net to Eni.

Development activities progressed during the year at the Shorouk concession where the Zohr gas offshore field is located, targeting to ramp up the field production capacity with a view of addressing the expected increase in the Country’s national gas demand. Two additional producing wells were drilled and linked to onshore production facility, reaching a gross production capacity of 3,200 mmcf/d. Also, optimization and upgrading activities of the subsea facilities and of the onshore treatment plant progressed.

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

As of December 31, 2020, the aggregate development costs incurred by Eni for developing the Zohr project and capitalized in the financial statements amounted to $5.5 billion (€ 4.5 billion at the EUR/USD exchange rate of December 31, 2020). Development expenditure incurred in the year were €73 million.

As of December 31, 2020, Eni’s proved reserves booked at the Zohr field amounted to 771 mmBOE. The Zohr proved reserves, both developed and undeveloped, related solely to the project phase 1.

In 2020, the Zohr reserves were subject to an independent evaluation.

Exploration activities yielded positive results with near-field discoveries in the operated areas: (i) the Nidoco NW-1 in the Abu Madi West concession (Eni’s interest 75%) and Bashrush gas discoveries (Eni’s interest 37.5%) in the Great Nooros Area; (ii) the SWM-A-6X oil discovery well in the South West Meleiha concession. The production start-up was achieved during the year; and (iii) the southern extension of the Arcadia field through the Arcadia 9 oil discovery well in the Meleiha concession and already in production.

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In 2020, Sub-Saharan Africa accounted for 21% of Eni’s total worldwide production of oil and natural gas.

Angola. In 2020, Angola accounted for 7% of Eni’s total worldwide production of oil and natural gas.

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In 2020 Eni was awarded the operatorship with a 60% interest in the offshore Block 28, in the Namibe basin, and a 42.5% interest in the onshore Cabinda Central block.

During the year, in the operated Block 15/06 (Eni’s interest 36.84%), production ramp-up was achieved at the Agogo 1 discovery well, connecting it to the Ngoma FPSO (West Hub project). Production started up just nine months after the discovery.

Other development activities in the operated Block 15/06 concerned: (i) the completion of the subsea production and injection facilities at the Cabaça North & UM 4/5 project (East Hub project); (ii) studies for the full field development of the Agogo field; and (iii) activities related to the Ndungu discovery development.

In October 2020, the unitization agreement of the three Development Areas of Block 14 (Eni’s interest 20%) was ratified with the related implementing decree. The agreements provide a new expiration date in 2028 and new development plan of the area as well as increasing entitlement volumes for the cost recovery.

Eni owns a 13.6% interest at the Angola LNG venture, which runs a plant, located in Soyo, with a treatment capacity of approximately 350 BCF/y of feed gas and a liquefaction capacity of 5.2 mmtonnes/y. In 2020 production net to Eni averaged approximately 20 KBOE/d.

Exploration activities yielded positive results in the operated Block 15/06, following a successful appraisal well of the Agogo discovery. The Block 15/06 exploration license was renewed for additional three years.

Congo. In 2020 production start-up was achieved at the Nené phase 2b project in the Marine XII block (Eni operator with a 65% interest). The full field development phase is expected in the second half of 2022.

Development activities concerned the expansion of the CEC power plant (Eni’s interest 20%), increasing the electricity generation capacity to 484 MW, with the installation of a third turbine in 2020. Natural gas supply to the plant will be ensured by the Marine XII block production.

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 Total. 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 for 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 that 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 which is a joint operation for IFRS accounting purposes, proportionally-consolidated in the Company Consolidated Financial Statements. 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.

Development activities continued at the Coral South project during 2020. The sanctioned Coral South project includes the construction, installation and commissioning and of an FPSO vessel linked to six subsea gas producing wells, where the gas will undergo treatment, liquefaction, storage and export, with a capacity of approximately 3.4 mmtonnes/y of LNG. The project has reached a progress of more than 80% and the production start-up is expected in 2022. The LNG produced will be sold by the Area 4 Concessionaires to BP under a long-term contract for a period of twenty years, with an option for an additional ten-year term.

Activities progressed at the Mamba Complex discoveries where Eni is the delegated operator for the offshore upstream activities and ExxonMobil is the delegated operator for the onshore midstream activities that include the liquefaction facilities of the natural gas. In 2019, the Mozambique authorities approved the unitization agreement between the Area 1 and Area 4.

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In this context, the Area 4 operators progressed activities towards a final investment decision (FID) for the Rovuma LNG project, which plan the construction of two onshore LNG trains with a capacity of approximately 7.6 mmtonnes/y each, fed by 24 subsea wells and facilities for storing and exporting LNG. In 2019, the plan of development (POD) was approved by the relevant Authorities.

Nigeria. In January 2021, Eni and the partners divested the onshore production and development block OML 17 (Eni’s interest 5%).

Development activities of the operated OMLs 60, 61, 62 and 63 blocks (Eni’s interest 20%) concerned: (i) production optimization programs with workover and drilling activities; and (ii) increasing generation capacity of the combined cycle power plant at Okpai. Natural gas production of the area will support the plant capacity. The first phase of the expansion project was completed, reaching an installed capacity of 780 MW.

Other development activities concerned: (i) the drilling of 8 oil wells in the EA offshore field in the Block 79 (Eni’s interest 5%); (ii) production optimization programs with workover activity in the Gbaran field in the OML 28 block (Eni’s interest 5%) and Forkados Yokri field in the OML 43 block (Eni’s interest 5%); (iii) the drilling of 4 oil wells in the western area of the Block 46 (Eni’s interest 5%); and (iv) the completion of an additional development well of the offshore Bonga field (Eni’s interest 12.5%).

Eni holds 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 treatment capacity of approximately 1,236 BCF/y of feed gas and a production capacity of 22 mmtonnes/y of LNG. Natural gas supplies to the plant are currently provided under a gas supply agreement from the SPDC JV (Eni’s interest 5%), TEPNG JV and the NAOC JV (Eni’s interest 20%). In 2020, the Bonny liquefaction plant processed approximately 1,135 BCF. LNG production is sold under long-term contracts and exported mainly to Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG.

The acquisition of the OPL 245 property made by Eni in 2011 is the subject of certain judicial proceedings described in “Item 18 – consolidated financial statement – Note 27”. The license is due to expire in May 2021. Eni filed a request for an extension of the term or the conversion of the license into a mining permit in accordance with the contractual terms. The Company has also filed an arbitration with an ICSID court to protect the value of its investment.

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Kazakhstan

Eni’s operations in Kazakhstan mainly regarded the Kashagan and the Karachaganak fields. In 2020, Kazakhstan accounted for 10% of Eni’s total worldwide production of oil and natural gas.

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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, which 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 contains a large amount of hydrocarbon resources, which are expected to be developed in phases. The NCSPSA expires at the end of 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 Total, Shell and ExxonMobil, each with a participating interest of 16.81%, CNPC with 8.33%, and Inpex with 7.56%.

In 2020, production at the Kashagan field averaged 56 KBBL/d of liquids and 52 mmCF/d of natural gas net to Eni. Gas volumes undergo a treatment and then are delivered to the national gas marketing and transportation company (KazTransGas); a part of the gas volumes is utilized as fuel gas. A part of the raw gas volumes (approximately 43%) is re-injected in the reservoir. The liquid production is stabilized at the Bolashak facilities and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline.

Current development plans envisage increasing the production capacity up to 450 KBBL/d by upgrading the existing associated gas compression handling. The ongoing activities, sanctioned in 2020, mainly concerned: (i) increasing gas reinjection capacity by means of upgrading the existing facilities; and (ii) delivering a part of gas volumes to a new onshore treatment unit operated by a third party, currently under construction.

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, 2020, Eni’s proved reserves booked for the Kashagan field amounted to 675 mmBOE, increased from 661 mmBOE in 2019.

As of December 31, 2020, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $10 billion (€8.1 billion at the EUR/USD exchange rate of December 31, 2020). This capitalized amount included: (i) $7.4 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.6 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. Costs incurred in the year were €27 million.

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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 lasting 40 years, until 2037. Eni and Shell are co-operators of the venture. Eni’s interest in the Karachaganak project is 29.25%.

In 2020, production of the Karachaganak field averaged 53 KBBL/d of liquids and 195 mmCF/d of natural gas net to Eni. This field is producing liquids from the deeper layers of the reservoir. The gas is marketed (about 50%) at the Russian gas plant of Orenburg; the remaining 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.

Within the gas treatment expansion projects of the Karachaganak field, activities concerned: (i) the ongoing activities of the Karachaganak Debottlenecking project and the construction of a fourth gas reinjection unit; and (ii) completion of the Front End Engineering Design of the Karachaganak Expansion Project (KEP). This latter project is scheduled to be achieved in several phases. The development program of the first phase, sanctioned at the end of 2020, provides the construction of a sixth injection line, the drilling of three additional injection wells and of a new gas compression unit. Start-up is expected in 2024.

As of December 31, 2020, Eni’s proved reserves booked for the Karachaganak field amounted to 507 mmBOE, increased from 448 mmBOE in 2019.

As of December 31, 2020, the aggregate costs incurred by Eni for the Karachaganak project capitalized in the financial statements amounted to $4.3 billion (€3.5 billion at the EUR/USD exchange rate of December 31, 2020). Costs incurred in the year were €147 million.

Rest of Asia

Eni’s operations in Rest of Asia are conducted mainly in Indonesia, Iraq and United Arab Emirates. In 2020, Eni’s operations in the Rest of Asia accounted for approximately 9% of its total worldwide production of oil and natural gas.

Indonesia. Activities are concentrated in the offshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 13 blocks.

In 2020 Eni was awarded the operatorship with 40% interest in the West Ganal exploration block.

Development activities are related to the offshore Merakes gas project in the operated East Sepinggan block (Eni’s interest 65%). The project foresees the drilling of five subsea wells, which will be tied-back to the Floating Production Unit (FPU) of the Jangkrik producing field (Eni operator with a 55% interest). Natural gas production will be processed by the FPU and then delivered via pipeline to the onshore plant, which is connected to the East Kalimantan transport system to feed the Bontang liquefaction plant or will be sold on a spot basis in the domestic market. Start-up is expected in 2021.

Iraq. Development activities concerned the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field, to achieve a production plateau of 700 KBBL/d. This phase also contemplates utilization of the associated gas for power generation. The production capacity and relevant facilities to treat the targeted production plateau have been already installed; the field reserves will be progressively put into production by drilling additional productive wells over the next few years.

Pakistan. In March 2021, Eni signed an agreement to divest the entire upstream activity in the Country including interests in eight development and production licenses to Prime International Oil&Gas local company. In particular, the agreement provides the disposal of the Bhit/Badhra (Eni’s interest 40%) and Kadanwari (Eni’s interest 18.42%) operated fields as well as the participating interest in the Latif (Eni’s interest 33.3%), Zamzama (Eni’s interest 17.75%) and Sawan (Eni’s interest 23.7%) fields.

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United Arab Emirates. In 2020, Eni awarded the operatorship with a 70% interest in the Block 3, located offshore Abu Dhabi. The exploration

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commitment for the first phase includes exploration studies, the drilling of exploration and appraisal wells.

In January 2021, production start-up was achieved at the Mahani field located in onshore concession of Area B (Eni’s interest 50%) in the Emirate of Sharjah, just one year since discovery and two years after signing the concession agreement. Development activities, sanctioned with the final investment decision, provide the progressive ramp-up with the tie-back of two additional productive wells. Drilling activities were already planned.

Americas

Eni’s operations in Americas are conducted mainly in Mexico, the United States and Venezuela. In 2020, Eni’s operations in the Americas area accounted for approximately 7% of its total worldwide production of oil and natural gas.

Mexico. The development activities mainly concern the full field development program of the operated license Area 1 (Eni’s interest 100%), already in

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production. Development drilling activities are ongoing and during the year 2020 were completed producing wells which were linked to the Miztón production platform. A subsequent development phase of the project includes the production start-up of the Amoca discovery by means of the installation of a new leased production platform, currently under construction, as well as the conversion and upgrading of an FPSO unit that will be completed in 2021 including all linking and treatment facilities. Production start-up is expected in 2022. During the year, the FEED phase for these two production platforms started up.

In February 2020, exploration activities yielded positive results with the Saasken offshore oil discovery in the operated Block 10 (Eni’s interest 65%).

United States. Eni holds: (i) interests in 48 exploration and production blocks in the Gulf of Mexico, of which 16 as operator; (ii) interests and operates 84 blocks in Alaska; and (iii) Alliance area in Texas.

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Venezuela. In 2020, Eni’s production of oil and natural gas averaged 41 KBOE/d and accounted for approximately 3% of Eni’s total production. Eni’s production comes mainly from the Perla gas field (Eni’s interest 50%). Oil production in the Gulf of Venezuela, the Corocoro field (Eni’s interest 26%), in the Gulf de Paria, and the Junín 5 oil field (Eni’s interest 40%), located in the Orinoco Oil Belt, has been negatively affected as a consequence of the difficult operational environment mainly due to the U.S. sanctions towards the country”. Production activities have been negatively affected by the ongoing distressed financial and political situation of the country. 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 fully recovered the overdue trade receivable owed by Iranian state- owned companies relating to the cost recovery of past projects due to enactment of the agreements signed in 2016. There were no more outstanding receivables towards Iran’s national oil companies as of December 31, 2020. Eni retains at December 31, 2020 a residual payable amounting to approximately $5 million, which will be settled upon de-registration of our local branch.

Global Gas & LNG Portfolio

Global Gas & LNG Portfolio engages in the wholesale activity of supplying and selling natural gas via pipeline and LNG, and the international transport activity. It also comprises gas trading activities targeting both hedging and stabilizing the Group’s commercial margins and optimize the gas asset portfolio. In 2020, Eni’s worldwide sales of natural gas amounted to 64.99 BCM. Sales in Italy amounted to 37.30 BCM, while sales in European markets were 23.00 BCM that included 3.67 BCM of gas sold to certain importers to Italy.

The business results of operations in 2020 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations.”

Supply of natural gas

In 2020, Eni subsidiaries’ total supply of natural gas was 62.16 BCM, down by 8.26 BCM, or 11.7% from 2019. Gas volumes supplied outside Italy (54.69 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 88% of total supplies, down by 10.16 BCM, or 15.7% compared to the previous year, due to lower volumes purchased in the Netherlands (down by 3.01 BCM), in Russia (down by 1.87 BCM), in Algeria (down by 1.44 BCM), in Libya (down by 1.42 BCM), partially offset by higher purchases in Norway (up by 0.76 BCM). Supplies in Italy (7.47 BCM) increased by 34.1% from 2019.

In 2020, main gas volumes from equity production derived from: (i) Eni fields located in the British and Norwegian sections of the North Sea (3 BCM); (ii) Italian gas fields (2.8 BCM); (iii) Libyan fields (1 BCM); (iv) Indonesia (0.6 BCM) and (v) the United States (0.3 BCM). Supplied gas volumes from equity production were approximately 7.7 BCM representing around 12% of total volumes available for sale. The available for sale by Eni’s affiliates amounted to 2.34 BCM (down by 8.9% compared to 2019) and mainly referred to supplied volumes from Oman, the United States and Spain.

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


Natural gas supply	2020		2019		2018
	(BCM)
Italy		7.47		5.57		5.46
Outside Italy		54.69		64.85		68.67
Russia		22.49		24.36		26.10
Algeria (including LNG)		5.22		6.66		12.02
Libya		4.44		5.86		4.55
the Netherlands		1.11		4.12		3.95
Norway		7.19		6.43		6.75
the United Kingdom		1.62		1.75		2.21
Indonesia (LNG)		1.15		1.58		3.06
Qatar (LNG)		2.47		2.79		2.56
Other supplies of natural gas		5.24		7.90		5.50
Other supplies of LNG		3.76		3.40		1.97
Total supplies of subsidiaries		62.16		70.42		74.13
Withdrawals from (input to) storage		0.52		0.08		0.08
Network losses, measurement differences and other changes		(0.03)		(0.22)		(0.18)
Volumes available for sale of Eni’s subsidiaries		62.65		70.28		74.03
Volumes available for sale of Eni’s affiliates		2.34		2.57		2.57
Total volumes available for sale		64.99		72.85		76.60

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 2020, natural gas sales amounted to 64.99 BCM (including Eni’s own consumption and Eni’s share of sales made by equity-accounted entities), representing a decrease of 7.86 BCM, or 10.8% from the previous year. Sales in Italy (37.30 BCM) decreased by 1.8% from 2019. Lower sales to thermoelectrical and industrial segments were partly offset by higher sales to hub. Sales in the European markets amounted to 19.33 BCM, a decrease of 13.5% or 3.02 BCM from 2019.

Sales to long-term buyers were 3.67 BCM, down by 16% compared to the previous year due to the lower availability of Libyan output.

Sales in the Extra European markets (4.69 BCM) decreased by 3.46 BCM or 42.5% due to lower LNG sales in the United States and in the Far East markets.

The tables below set forth Eni’s sales of natural gas by principal market for the periods indicated.


Natural gas sales by entities	2020		2019		2018
	(BCM)
Total sales of subsidiaries		62.58		70.17		73.68
Italy (including own consumption)		37.30		37.98		39.17
Rest of Europe		21.54		25.21		27.42
Outside Europe		3.74		6.98		7.09
Total sales of Eni’s affiliates (Eni’s share)		2.41		2.68		2.92
Italy
Rest of Europe		1.46		1.51		1.75
Outside Europe		0.95		1.17		1.17
Worldwide gas sales		64.99		72.85		76.60

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Natural gas sales by market	2020		2019		2018
			(BCM)
ITALY		37.30		37.98		39.17
Wholesalers		12.89		13.08		14.67
Italian gas exchange and spot markets		12.73		12.13		12.49
Industries		4.21		4.62		4.40
Power generation		1.34		1.90		1.50
Own consumption		6.13		6.25		6.11
INTERNATIONAL SALES		27.69		34.87		37.43
Rest of Europe		23.00		26.72		29.17
Importers in Italy		3.67		4.37		3.42
European markets		19.33		22.35		25.75
Iberian Peninsula		3.94		4.22		4.65
Germany/Austria		0.35		2.19		1.93
Benelux		3.58		3.78		5.29
United Kingdom/Northern Europe		1.62		1.75		2.22
Turkey		4.59		5.56		6.53
France		5.01		4.47		4.95
Other		0.24		0.38		0.18
Extra European markets		4.69		8.15		8.26
WORLDWIDE GAS SALES		64.99		72.85		76.60

The LNG business

Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from, Qatar, Nigeria, Indonesia and Oman. 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, China, Pakistan and Taiwan. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities.


LNG sales	2020		2019		2018
	(BCM)
Europe		4.8		5.5		4.7
Extra European markets		4.7		4.6		5.6
		9.5		10.1		10.3

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.

Eni also retains ownership interests in certain pipeline companies, which run and operate the facility by selling transportation capacity under long-term ship-or-pay contracts to both shareholders and third party shippers. The main assets of Eni’s transport activities are provided in the table below.

International Transport infrastructure Route

	Lines	Total length		Diameter		Transport capacity		Compression stations
	(units)	(km)		(inch)		(BCM/y)		(No.)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of km 370		740		48		34.3		5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of 155		775		20/26		33.5
GreenStream (Mellitah-Gela)	1 line of km 520		520		32		8.0		1
Blue Stream (Beregovaya-Samsun)	2 lines of km 387		774		24		16.0		1

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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 at the Oued Saf Saf entry point 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.

The GreenStream pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometers long with an originally transport capacity of 8 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.

Eni holds an interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking 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.

Capital expenditures

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

Refining & Marketing and Chemicals

Refining & Marketing

Eni’s Refining & Marketing business engages in the supply and refining of crude oil to produce a large slate of fuels and other refined products and in the marketing of fuels primarily in Italy and in selected European markets. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company operations are fully integrated through refining, supply, logistics and marketing in order to maximize cost efficiencies and operational effectiveness.

The Company also engages in the production of bio-fuels at the Venice and Gela refineries, where certain renewable feedstock are processed (palm oil).

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 2020 refining margins in the Mediterranean area decreased by 60% as compared to the prior year to 1.7 $/BBL driven by a materially lower demand for fuels, which was hit by the pandemic crisis affecting economic activity and travel, against a backdrop of overcapacity, competitive pressure and high inventory levels. The weak scenario was exacerbated by a recovery in the cost of the oil feedstock, which was supported by implementation of production cuts resolved by the OPEC+ agreement. Refining margins were also penalized by narrowing spreads between sour crudes like the Ural vs. light-sweet crudes, such as the Brent, due to the lower availability of sour crudes due to OPEC+ cuts, which resulted in low margins at conversion plants.

Eni believes that the competitive environment of the refining sector will remain challenging in the foreseeable future considering ongoing uncertainties and risks relating to the strength of the economy recovery in Europe and worldwide, and risks of another round of lockdown measures in case of failure on part of governments to effectively contain the spread of the pandemic, which would weigh heavily on demand for fuels. Other risks factors include refining overcapacity in the European area and expectations of a new investment cycle driven by capacity expansion plans announced in Asia and the Middle East, potentially leading to a situation of global oversupplies of refinery products.

The business results of operations in 2020 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations”.

Supply

In 2020, a total of 17.37 mmtonnes of crude were purchased (compared with 23.43 mmtonnes in 2019), of which 3.55 mmtonnes were equity crude oil. The breakdown by geographic area was the

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following: approximately 26% of purchased crude came from the Middle East, 17% from Central Asia, 16% from Russia, 16% from Italy, 8% from West Africa, 7% from North Africa, 4% from North Sea and 6% from other areas.

Refining

In 2020, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 KBBL/d), with a conversion index of 54%. 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 19.4 mmtonnes (equal to 388 KBBL/d), with a 55% conversion index. In 2020, Eni’s refineries throughputs in Italy and outside Italy were 17 mmtonnes. The average refinery utilization rate, ratio between throughputs and refinery capacity, is 69%.

	Ownership %		Balanced refining capacity (Eni’s share) (1) (KBBL/d)		Utilization rate (Eni’s share) %		Conversion index(2) %

Wholly-owned refineries				388		66		55
Italy
Sannazzaro		100		200		61		73
Taranto		100		104		73		56
Livorno		100		84		72		11
Partially owned refineries				160		76		52
Italy
Milazzo		50		100		78		60
Germany
Vohburg/Neustadt (Bayernoil)		20		41		63		36
Schwedt		8.33		19		94		42
Total				548		69		54

(1)

Including 20% share in ADNOC Refining, balanced refining capacity amounted to 732 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 200 KBBL/d and a conversion index of 73%. 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 equipment 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 thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.

The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 56%. Taranto has a strong market position due to the fact that it is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni 61%) through a pipeline. The main equipment 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.

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The Milazzo refinery (Eni 50%) has a balanced capacity of 200 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipment in the refinery 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. The refinery supplies Eni’s distribution network in the country.

Biorefineries

	Ownersip share (%)		Capacity (2020) (mmtonnes/y)		Throughput (2020) (mmtonnes/y)
Wholly-owned
Venezia		100		0.4		0.2
Gela		100		0.7		0.5
Total biorefineries				1.1		0.7

Eni fully owns two biorefineries in Italy, specifically in Venice and Gela.

The Venice biorefinery started production in June 2014, replacing the old oil-based refinery that was shut down. The refinery, with a production capacity of 0.4 mmtonnes/y, leverages on the Ecofining™ proprietary technology to transform vegetable oil into hydrogenated bio-fuels. A second phase of development is underway to achieve a full capacity of 0.56 mmtonnes/y. At full capacity, the refinery production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental regulations aimed at reducing CO2 emissions.

The Gela refinery is located in the Southern coast of Sicily. The refinery was shut-down in March 2014 for the conversion of the plant into a biorefinery. In 2017 the project obtained the environmental impact assessment and authorization (VIA/AIA) by the Italian Ministry of the Environment and the Ministry of Cultural Heritage. In August 2019, Eni started-up the biorefinery equipped with the EcofiningTM technology, developed and licensed by Eni, to convert into biodiesel, vegetable oil and second generation raw materials, such as used cooking oil and animal fat. The plant properties allow the production of biodiesel in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain, deploying the full capacity in process second-generation feedstock.

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


Availability of refined products	2020		2019		2018
	(mmtonnes)
ITALY
Refinery throughputs
At wholly-owned refineries		12.72		17.26		16.78
Less input on account of third parties		(1.75)		(1.25)		(1.03)
At affiliated refineries		3.85		4.69		4.93
Refinery throughputs on own account		14.82		20.70		20.68
Consumption and losses		(0.97)		(1.38)		(1.38)
Products available for sale		13.85		19.32		19.30
Purchases of refined products and change in inventories		7.18		7.27		7.50
Products transferred to operations outside Italy		(0.66)		(0.68)		(0.54)
Consumption for power generation		(0.35)		(0.35)		(0.35)
Sales of products		20.02		25.56		25.91
Biorefinery throughputs		0.71		0.31		0.25
OUTSIDE ITALY
Refinery throughputs on own account		2.18		2.04		2.55
Consumption and losses		(0.17)		(0.18)		(0.20)
Products available for sale		2.01		1.86		2.35
Purchases of finished products and change in inventories		3.39		4.17		4.12
Products transferred from Italian operations		0.66		0.68		0.54
Sales of products		6.06		6.71		7.01
Refinery throughputs on own account		17.00		22.74		23.23
of which: refinery throughputs of equity crude on own account		3.55		4.24		4.14
Total sales of refined products		26.08		32.27		32.92
Crude oil sales		0.67		0.44		0.28
TOTAL SALES		26.75		32.71		33.20

In 2020, Eni’s refining throughputs on own account in Europe were 17 mmtonnes, decreased by 25.2% from 2019, due to the lower throughputs processed in Italy as a result of the depressed refining scenario and storage saturation as a consequence of the impact of COVID-19 on demand. These negatives were partially offset by the restart of some plants in Vohburg and PCK (maintenance turnaround in 2019) in Germany.

In Italy, the refinery throughputs (14.82 mmtonnes) decreased by 28.4% from 2019 following the depressed refining scenario.

Outside Italy, Eni’s refining throughputs on own account were 2.18 mmtonnes, up by approximately 140 ktonnes or 6.9% due to the abovementioned restart of Vohburg plant and PCK in Germany. Total throughputs in wholly-owned refineries were 12.72 mmtonnes, down by 4.54 mmtonnes or 26.3% compared with 2019.

The refinery utilization rate, ratio between throughputs and refinery capacity, is 69%.

Approximately 21.2% of processed crude was supplied by Eni’s Exploration & Production segment, increasing by 18.9% from 2019.

The volumes of biofuels processed from vegetable oil increased by 0.40 mmtonnes compared to 2019, due to the ramp-up of the Gela bio-refinery.

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.

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Eni also owns a network of oil and refined products pipelines extending approximately 1.156 kilometers. Eni’s logistic model is organized in four hubs (Northern depots, Central depots, Southern depots and Pipeline). They manage the product flows in order to guarantee high safety, asset integrity and technical standards, as well as cost effectiveness 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 to retail and wholesale markets is outsourced to independent trucks, selected as market leaders.

Marketing

Eni 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	2020		2019		2018
	(mmtonnes)
Italy
Retail		4.56		5.81		5.91
Wholesale		5.75		7.68		7.54
		10.31		13.49		13.45
Petrochemicals		0.61		0.83		0.96
Other sales		9.10		11.24		11.50
Total		20.02		25.56		25.91
Outside Italy
Retail		2.05		2.44		2.48
Wholesale		2.88		3.11		3.29
		4.93		5.55		5.77
Other sales		1.13		1.16		1.24
Total		6.06		6.71		7.01
TOTAL SALES		26.08		32.27		32.92

In 2020, retail sales of refined products (26.08 mmtonnes) were down by 6.19 mmtonnes or by 19.2% from 2019, mainly due to the COVID-19 crisis which negatively affected sales in Italy and in the rest of Europe.

Retail sales in Italy

In 2020, retail sales in Italy were 4.56 mmtonnes, with a decrease compared to 2019 (1.25 ktonnes from 2019 or down by 21.5%) as result of the lockdown measures imposed mainly in the second quarter, during the pandemic peak. Average gasoline and gasoil throughput (1,206 kliters) down by 380 kliters. Eni’s retail market share of 2020 was 23.3%, slightly down from 2019 (23.6%). As of December 31, 2020, Eni’s retail network in Italy consisted of 4,134 service stations, lower by 50 units from December 31, 2019 (4,184 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (46 units), closure of low throughput stations (3 units) and a decrease of 1 motorway concession.

Retail sales in the Rest of Europe

Retail sales in the Rest of Europe were 2.05 mmtonnes, recording a reduction from 2019 (down by 16%) mainly due to the measures adopted against COVID-19 in the second quarter during the pandemic peak.

At December 31, 2020, Eni’s retail network in the Rest of Europe consisted of 1,235 units, increasing by 8 units from December 31, 2019, mainly in Germany and France. Average throughput (1,980 kliters) decreased by 376 kliters compared to 2019 (2,356 kliters).

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Other businesses

Wholesale

Eni is strongly present in the wholesale market in Italy, including sales of diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and 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.). Eni 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 are articulated in local marketing offices and a network of agents and concessionaires.

In 2020, sales volumes on wholesale markets in Italy (5.75 mmtonnes) decreased by 25.1% from 2019, due to the reduction of industrial activity and in particular because of lower sales of jet fuel following a deep crisis of the airlines sector.

Wholesale sales in the Rest of Europe were 2.40 mmtonnes, down by 8.7% from 2019 due to lower sold volumes in Spain, partly offset by higher volumes in Germany as a result of higher product availability due to the restart of Vohburg plant.

Supplies of feedstock to the petrochemical industry (0.61 mmtonnes) decreased by 26.5%. Other sales in Italy and outside Italy (10.23 mmtonnes) decreased by 2.17 mmtonnes or down by 17.5%, mainly due to lower 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 three 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 2020, Eni share of LPG market in Italy was 15.3%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 37.4%.

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 international state 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 2020, Eni’s share of lubricants market in Italy was 21%, 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 820 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 75% 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 25% is purchased.

Chemicals

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 chemical products from renewable sources and recycled materials.

The business results of operations in 2020 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations”.

In 2020 sales of chemical products amounted to 4,339 ktonnes, slightly increased from 2019 (up by 44 ktonnes, or 1%) thanks to the positive performance reported in the intermediate, styrenics and polyethylene segments, due to the accelerated economic recovery in the fourth quarter, mainly in Asia and

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lower competitive pressure, partly mitigated by the generalized reduction in volumes during the pandemic peak in the second quarter and by the global economic downturn which affected all the main end-markets, particularly the automotive sector, and the subsequent conservative position of operators which induced to decrease storage.

Average sale prices of the intermediates business decreased by 23.3% from 2019, with aromatics and olefins down by 36.4% and 25.4%, respectively. The polymers reported a decrease of 15% from 2019.

Petrochemical production of 8,073 ktonnes were substantially unchanged from 2019 (up by 5 ktonnes) mainly due to higher production of intermediates business (up by 43 ktonnes), in particular olefins, partly offset by the reduced elastomers and polyethylene productions (down by 23 ktonnes and down by 18 ktonnes, respectively).

The main decreases in production were registered at the Priolo site (down by 207 ktonnes), due to the prolonged planned shutdown and at Brindisi (down by 33 ktonnes); these reductions were offset by higher volumes at Porto Marghera plant (up by 246 ktonnes).

Plants nominal capacity slightly decreased from the 2019. The average plant utilization rate, calculated on nominal capacity was 65%, decreasing from 2019 (67%) following the aforementioned shutdowns.

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

	Year ended December 31,
	2020		2019		2018
	(ktonnes)
Intermediates		5,861		5,818		7,130
Polymers		2,212		2,250		2,353
Total production		8,073		8,068		9,483
Consumption and losses		(4,366)		(4,307)		(5,085)
Purchases and change in inventories		632		534		548
		4,339		4,295		4,946

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

	Year ended December 31,
	2020		2019		2018
	(€ million)
Intermediates		1,385		1,791		2,401
Polymers		1,888		2,201		2,589
Other revenues		114		131		133
Total revenues		3,387		4,123		5,123

Intermediates

Intermediates revenues (€1,385 million) decreased by €406 million from 2019 (down by 22.7%) reflecting both the lower commodity prices scenario and the lower product availability due to plant standstills. Sales increased by 2.4% and by 0.8% in aromatics and olefins, respectively, following the higher product availability.

Average prices decreased by 23.3%, in particular aromatics (down by 36.4%), olefins (down by 25.4%) and derivatives (down by 5.9%).

Intermediates production (5,861 ktonnes) registered an increase of 0.7% from 2019. Increases were registered in olefins (up by 1.7%), decreases in derivatives (down by 3.9%) and in aromatics (down by 0.8%).

Polymers

Polymers revenues (€1,888 million) decreased by €313 million or 14.2% from 2019 due to the decrease of the average unit prices (down by 15%).

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The styrenics business benefited of the increase of volumes sold (up by 4%) for higher product availability; decrease of sale prices (down by 16%).

Polyethylene volumes increased (up by 2%) for higher demand. Average prices decreased by 13.4%.

In the elastomers business, a decrease of sold volumes (down by 4.6%) was attributable to lattices (down by 8.4%), EPR (down by 6.5%), TPR (down by 4.8%), SBR rubbers (down by 4.6%) and BR rubbers (down by 3%).

Higher styrenics volumes sold (up by 4%) were mainly attributable to ABS (up by 7.8%), expandable polystyrene (up by 5.1%) and compact polystyrene (4.5%), these higher volumes were partly offset by lower sales of styrene (down by 12.7%).

Overall, the sold volumes of polyethylene business reported an increase (up by 2%) with higher sales of LLDPE and EVA (up by 4.6% and 7.3%, respectively), while volumes of LLDPE decreased (down by 2.3%). In addition, average sale prices decreased (down by 13.4%).

Polymers productions (2,212 ktonnes) decreased from the 2019 due to the lower productions of elastomers (down by 6.7%), polyethylene (down by 1.9%).

Capital expenditures

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

Eni gas e luce, Power & Renewables

Eni gas e luce, Power & Renewables engages in the activities of retail sales of gas, electricity and related services, as well as in the production and wholesale sales of electricity from thermoelectric and renewable plants. 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 2020 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations.”

Eni gas e luce

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. Overall Eni supplies 9.6 million retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 7.7 million.

Retail sales

Gas sales by market		2020		2019		2018

ITALY	(bcm)		5.17		5.49		5.83
Residential			3.96		3.99		4.20
Small and medium-sized enterprises and services			0.70		0.87		0.79
Industries			0.28		0.30		0.39
Resellers			0.23		0.33		0.45
INTERNATIONAL SALES			2.51		3.13		3.30
European markets:
France			2.08		2.69		2.94
Greece			0.34		0.35		0.24
Other			0.09		0.09		0.12
RETAIL GAS SALES			7.68		8.62		9.13

Retail gas sales, in Italy and in European markets, amounted to 7.68 BCM, down by 0.94 BCM or 10.9% from 2019. Sales in Italy decreased by 5.8%, amounting to 5.17 BCM, mainly due to lower volumes marketed at small and medium enterprises and resellers segments; the reduction reported in the residential segment was mitigated by the positive weather effect mainly in the last quarter of the year.

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Sales in the European market were 2.51 BCM, decreasing by 19.8% (down by 0.62 BCM) compared to 2019. In France, sales decreased by 22.7% due to lower volumes marketed to industrial customers. In Greece and Slovenia sales were substantially in line with the comparative period.

In Europe Eni gas e luce operates through the subsidiary Eni gas&power France SA (99.87% EGL interest) in France, Gas Supply Company of Thessaloniki (100% EGL interest) in Greece, Adriaplin doo (51% EGL interest) in Slovenia.

In 2020, retail power sales to end customers, managed by Eni gas e luce and subsidiaries companies in France and Greece, amounted to 12.49 TWh, an increase by 14.4% from the full year 2019, due to growth of retail customers portfolio (up by around 270,000 customers vs. 2019) and higher volumes sold to the retail and industrial segments in Europe.

Power

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, on the Italian wholesale energy 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 2020, power sales in the open market were 25.33 TWh, representing a reduction of 10.4% compared to 2019 due to economic downturn.

Power availability	2020		2019		2018
	(TWh)
Power generation sold		20.95		21.66		21.62
Trading of electricity(a)		17.09		17.83		15.45
		38.04		39.49		37.07
Power sales in the open market		25.33		28.28		28.54

(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, 2020, installed operational capacity of Enipower’s power plants was 4.6 GW. In 2020, thermoelectric power generation was 20.95 TWh, substantially in line compared to 2019. Electricity trading (17.09 TWh) reported a decrease of 4.2% from 2019, thanks to the optimization of inflows and outflows of power.

Site

Total installed
capacity in 2020
(MW)

Technology

Fuel

Brindisi

1,268

CCGT

gas

Ferrera Erbognone

1,052

CCGT

gas/syngas

Mantova

851

CCGT

gas

Ravenna

984

CCGT

gas

Ferrara(a)

400

CCGT

gas

Bolgiano

Power station

gas

4,619

(a)

Eni’s share of capacity.

Power generation		2020		2019		2018
Purchases
Natural gas	(mmCM)		4,346		4,410		4,300
Other fuels	(ktoe)		160		276		356
- of which steam cracking			88		91		94
Production
Electricity	(TWh)		20.95		21.66		21.62
Steam	(ktonnes)		7,591		7,646		7,919
Installed generation capacity	(GW)		4.6		4.7		4.7

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Renewables

Eni is engaged in the renewable energy business (solar and wind) through the business unit Energy Solutions aiming at developing, constructing and managing renewable energy producing plant.

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 international strategic partnership.

Energy from renewable sources and installed capacity at period end

		2020		2019		2018
Energy production sold from renewable sources	(GWh)		339.6		60.6		11.6
of which: photovoltaic			223.2		60.6		11.6
onshore wind			116.4
of which: Italy			112.2		53.3		11.6
outside Italy			227.4		7.3
of which: own consumption⁽*⁾			23%		60%		75%
Installed capacity from renewables at period end	(MW)		307		174		40
of which: photovoltaic			77%		76%		100%
onshore wind			20%		20%
installed storage capacity			3%		4%

⁽*⁾

Electricity for Eni’s production sites consumptions.

Energy production from renewable sources amounted to 339.6 GWh in 2020 (of which 223.2 GWh photovoltaic and 116.4 GWh wind) up by 279 GWh compared to 2019.

The increase in production compared to the previous year benefitted from the entry in exercise of new capacity, as well as the contribution of assets already operating in the United States, acquired in 2020.

Installed capacity from renewables at period end (Eni’s share)

(megawatt)				2020		2019		2018
	% Eni’s share		technology
ITALY					84		82		35
Assemini (CA)		100	photovoltaic (fixed)		23		23		23
Porto Torres (SS)		100	photovoltaic (fixed)		31		31
Volpiano (TO)		100	photovoltaic (fixed)		18		16
Ferrera Erbognone (PV)		100	photovoltaic (fixed)		1		1		1
Gela – Isola 10 (CL)		100	photovoltaic (tracker)		1		1		1
Gela – ISAF (CL)		100	photovoltaic (fixed)		5		5		5
Gela – RaGe (CL)		100	photovoltaic (fixed)		1		1		1
Other plants		100	photovoltaic (fixed)		4		4		4
OUTSIDE ITALY					223		92		5
Algeria – BRN		50	photovoltaic (fixed)		5		5		5
Kazakhstan – Badamsha		100	onshore wind		48		34
Australia – Katherine		100	photovoltaico (tracker + storage)		39		39
Australia – Batchelor & Manton		100	photovoltaic (tracker)		25
Pakistan – Bhit		100	photovoltaic (tracker)		10		10
Tunisia – Adam		50	photovoltaic (fixed + storage)		4		4
Tunisia – Tataouine		50	photovoltaic (tracker)		5
United States (11 plants)		49	photovoltaic (tracker/fixed + storage) and onshore wind		87
TOTAL INSTALLED CAPACITY AT YEAR END (INCLUDING INSTALLED STORAGE POWER)					307		174		40
of which installed storage power					8		7

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At the end of 2020, the total installed capacity for the generation of energy from renewable sources amounted to 307 MW (in Eni share and including the storage power), of which about 84 MW in Italy and 223 MW abroad, with 30 plants in operation.

The capacity under construction/advanced stage of development amounted to about 0.7 GW and mainly relating to the Dogger Bank A and B offshore wind projects in the UK (480 MW in Eni share) and the new capacity in Kazakhstan (98 MW, of which 48 MW onshore wind and 50 MW solar photovoltaic).

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. 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. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations.

Seasonality

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

Research and development

Integration, efficiency and application of technologies are the strategic levers that characterize the R&D operating model, along the entire energy value chain. At the base of the application of technologies, Research and Technological Innovation are a pillar for the organic growth of the company, allowing to consolidate the know-how and to enrich it, contributing to the training of internal skills and technological evolution.

The objectives are set out on the following strategic directives, defined as technological platforms:

•

Operational Excellence, to develop innovative technologies for the development of assets, increasing energy efficiency, ensuring the highest level of safety and minimum environmental impact, while reducing capex, opex and time to market of our environmental activities.

•

Carbon Neutrality, to reduce, capture, transform or store CO2, promoting natural gas as an energy source in the transition to a low-carbon energy mix, integrating it with renewables and developing innovative energy technologies.

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•

Circular economy, to reduce the use of raw materials, including through recycling, transforming waste into products with added value, in view of a sustainable development based on the principles of circular economy.

A key point of our research and innovation is the integrated and transversal approach. The technology research and development team is indeed at the center of a fruitful exchange of experiences, problem solving and knowledge management in the company – providing experience, solutions, innovation and expertise.

Research and Development becomes, therefore, the 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 2020, Eni filed 25 patent applications (34 in 2019).

In 2020, Eni’s overall expenditure in R&D amounted to €157 million which were almost entirely expensed as incurred (€194 million in 2019 and €197 million in 2018).

Producing energy with the lowest carbon footprint is the challenge that every energy company is called to meet today. To win this challenge, we are investing in scientific and technological research. In 2020, about half of total R&D expenditures were dedicated to the decarbonization pathway and the circular economy. In the R&D projects, the skills of at least 1500 Eni people have been used, with the collaboration of more than 70 Universities and Research Centers, among the most important in Italy and the rest of the world. Our commitment to decarbonization and the energy transition is also reflected in the partnerships we have forged with the Oil and Gas Climate Initiative (OGCI), Commonwealth Fusion Systems LLC (CFS), Divertor Tokamak Test (DTT) and leading universities and research institutions, including ENEA, CNR and MIT. To multiply access to high-impact emerging technologies, we have adopted an Open Innovation approach through Eni Next and in OGCI-Climate Investments. Thanks to these collaborations we want to continue to develop our network with universities, research centers, start-ups, hi-tech companies and all the realities that are preparing the low-carbon energy future. At the same time, we will continue to invest in venture capital initiatives and in the development and deployment of disruptive technologies, with a focus on Circular Economy, Decarbonisation and Renewable Energies.

The challenge, in this context, is not only on the technologies, but also and especially on their implementation: Eni is committed to increasingly accelerate the technological “time to market”, developing in parallel the pilot, pre-commercial demonstration and first industrial application phases.

In order to reduce the risks related to the timing of technological development, Eni’s research focuses on the growth of internal skills, but also on collaborations with the academic and technological world, both national and international, thanks to a series of framework agreements, alliances with the main technological and industrial players, the creation of large interdisciplinary and multi-business programs and an R&D structure that is a crossroads for all technical disciplines.

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.

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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 Oil Insurance 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 Oil Insurance 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 LNG tankers and time 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”.

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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.

International and European Union Environmental Laws Framework

On November 4, 2016, the Paris Agreement entered into force, exactly 30 days after the date on which the last of at least 55 Parties to the Convention accounting in total for at least an estimated 55% of the total

global greenhouse gas emissions have deposited their instruments of ratification. To date, 189 Parties have ratified the Convention. This important step in the common international Climate Change strategy sets out a global action plan to keep a global temperature rise this century well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase even further to 1.5°C.

In 2019, the UN Climate Change Conference (COP 25) had taken place in Madrid under the Presidency of the Government of Chile. The COP 25 had an important role to play in moving forward with the Paris Agreement “rule- book” implementation and it laid the basis for more ambitious emission reduction commitments from Parties at the next conference (COP 26 to be held in Glasgow, UK). Main focus areas discussed during the COP 25 were adaptation to climate impacts, the support to loss and damage suffered by developing nations due to climate change, international climate finance and others. Regarding the rules for the international carbon market (article 6 of the Paris Agreement), the COP 25 did not reach any agreement. On this topic, negotiations could not go over the impasse due to a divergence between the Parties on a few crucial points and in the end, the issue was delayed until next year’s talks.

In 2020, other than agreeing upon a common framework for international carbon market, the Parties are required to submit new or updated national climate action plans, referred as Nationally Determined Contributions (NDCs) and, in this task, Parties are urged to consider the significant gap between the current emission pathways and the pathways consistent the Paris Agreement mitigation target.

During the COP 25, the European Union (EU) released the Green Deal Communication, in which it clearly announces its commitment on the environmental aspects. The document represents a package of measures that should enable European citizens and businesses to benefit from sustainable green transition. Measures accompanied with an initial roadmap of key policies range from ambitiously cutting emissions, to investing in cutting-edge research and innovation, to preserving Europe’s natural environment and achieving a climate neutral economy by 2050. The roadmap includes also a comprehensive plan to increase the EU’s GHG reduction target for 2030 to at least 50% and toward 55% vs 1990, compared to current target of 40%.

Once implemented in legislation, the new EU 2030 GHG reduction target will entail a revision of the main targets and provisions enforced by the current EU legislation. In particular, the existing Clean Energy for All Europeans (so called “Clean Energy Package”) developed between 2016 and early 2019, among the others commitments, set a binding target of 32% for renewable energy sources in the EU’s energy mix by 2030 and a binding target of at least 32.5% energy efficiency by 2030, relative to a ‘business as usual’ scenario.

The revised Renewable Energy Directive sets also the target for renewable energy in the transport sector. In particular, Member States must require fuel suppliers to supply a minimum of 14% of the energy consumed in road and rail transport by 2030 as renewable energy, of which at least 3.5% coming from advanced biofuels. In terms of environmental sustainability, high Indirect Land Use Change-risk feedstocks will be capped at 2019 levels until 2023 and then progressively phased-out up to zero by 2030.

A centerpiece of the EU’s 2030 energy and climate policy framework is the binding target to reduce overall GHG emissions by at least 40% below 1990 levels by 2030. To achieve this cost-effectively, the sectors covered by the EU Emission Trading System (EU ETS) will have to reduce their emissions by 43% compared with 2005, while non-ETS sectors will have to reduce theirs by 30%. The ETS is about to enter in its IV phase (2021-2030), in which the European cap will decline at an annual rate of 2.2%, compared to 1.74% of the previous phase. The carbon leakage sectors will still receive 100% of the free allowances calculated with the sectorial benchmark, for all the IV phase. All the Eni’s activity sectors are included in the new carbon leakage list, excluding the extraction and production of natural gas. Currently around 46% of Eni’s direct GHG emissions are included within the Carbon Pricing Scheme by its participation in the EU ETS.

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In May 2018, the European institutions adopted the Effort Sharing Regulation (ESR) to ensure further emission reductions in sectors falling outside the scope of the EU ETS for the IV phase. The ESR maintains existing flexibilities (e.g. banking, borrowing and buying and selling between Member States) and provides two new flexibilities, allowing the use of some EU ETS emissions allowances and credits from land use sector to achieve the final target.

The Clean Energy Package includes also a new regulation on Governance of Energy Union, which asks all the Member States to draft their own National Energy and Climate Plans (NECPs), in order to plan, in an integrated manner, their climate and energy objectives, policies and measures, aligned with the broad EU targets. During 2019, most of the Member States presented their NECP for 2021-2030 period, to achieve their respective targets.

Under the electricity market reform, the European Commission approved a new limit for power plants eligible to receive subsidies as capacity mechanisms. Subsidies to generation capacity emitting 550 gCO2/ kWh or more will be phased out, as of 2020 for new infrastructure and as of 2025 for existing plants. The criterion, used in the European Investment Bank’s policy, is technology neutral and in practice preclude from the subsidies the coal power plants and some inefficient gas plants.

In the second half of 2019, the European Investment Bank (EIB) also approved the new energy lending policy, according to which, the EIB will no longer consider new financing for unabated, fossil fuel energy projects, including gas, from the end of 2021 onwards. In addition, the bank set a new Emissions Performance Standard of 250 gCO2/kWh as a threshold for its investments in both fossil and renewable energy sources.

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). These Directives set air quality standards and requirements to ensure that Member States monitor and/or assess air quality in their territory, in a harmonized and comparable manner. The fitness check of the AAQ Directives was based on the analysis of the experience in all Member States, focusing on the period from 2008 to 2018 and evaluated the relevance, effectiveness, efficiency, coherence and EU added value of the AAQ Directives, in line with Better Regulation requirements.

In order to guarantee better quality standards and to shift toward a low carbon economy, in December 2017, the Commission has launched the Clean Mobility Package. This is a decisive step forward in implementing the EU’s commitments under the Paris Agreement for a binding domestic CO2 reduction of at least 40% till 2030. Its aim is to help accelerate the transition to low- and zero emissions vehicles, through a new target for the EU fleet wide average CO2 emissions of new passenger cars and vans of 30% by 2030 to provide stability and long-term direction. The Mobility Package has a 2025 intermediary target of 15% to ensure that investments kick-start already now. As the confirmation of Eni’s involvement in sustainable mobility in November Eni and FCA have signed a contract to carry out research and develop technological applications aimed at reducing CO2 emissions in road transport.

On December 31, 2016, the new National Emissions Ceilings (NEC) Directive entered into force to guarantee stricter limits on the five main pollutants in Europe: sulfur dioxide (SO2), nitrogen oxides (NOx), ammonia (NH3), volatile organic compounds (VOC) and primary particulate matter (PM). The Member States had time until June 30, 2018 to transpose the NEC Directive and had to submit the First National Air Pollution Control Programmes by April 1, 2019, setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments. The NEC directive aim is to improve not only human health but also the condition of ecosystems across the EU. In 2019 the Commission Guidance on the monitoring ecosystem impacts of air pollution was released. Moreover the first data on air pollution impacts on ecosystems was supposed to be submitted by Member States by 1 July 2019. in line with Directive 2016/2284 (National Emission Ceilings).

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 envisaged in the road map of the European Green Deal, the review of the IED Directive came into focus during 2020. In 2021, the EU Commission will propose a revision of the measures to tackle pollution from large industrial plants in order to move faster towards the 2050 zero pollution target and support

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climate, energy and circular economy policies. To this end, in December 2020 the public consultation aimed at stakeholders was opened and will end in March 2021. Areas for improvement include: expansion of sectoral coverage; improvement of key provisions relating to the authorization and control of industrial facilities; more active participation of civil society representatives in the decision-making process relating to authorizations; and ensuring greater access to environmental information, including through revision of the Regulation on the Pollutant Release and Transfer Register (E-PRTR), which is closely related to the IED.

In October 2020, the evaluation carried out by the European Commission on the actual impact of the Directive on the reduction of emissions in the previous years was published in order to analyze to what extent the Directive itself is able to support the policies linked to the “Zero Pollution ambition for a toxic-free environment”. The EU wants to outline the actions to be taken at European level to achieve the ambitious “Zero Pollution” target for water, air and soil for a toxic-free environment. In October 2020, the EU Commission launched the first phase of consultation (Roadmap) on a set of proposals to achieve the challenging “Zero Pollution” target.

In 2016, the Commission published the Implementing Decision (EU) 2016/902 of May 30, 2016 establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU, for common wastewater and waste gas treatment/management systems in the chemical sector.

In February 2019, the Best Available Techniques Reference Document for the Management of Waste from Extractive Industries was published. In accordance with Directive 2006/21/EC, the reviewed document presents up -dated data and information on the management of waste from extractive industries, including information on BAT, associated monitoring, and developments in them. The new risk-based “BAT” approach considers the diversity of types of extractive waste, sites and operators and covers a wide range of potential risks that must be considered by operators responsible for waste management in the extractive industries.

In August 2017 the Commission Implementing decision 2017/1442 of July 31, 2017 entered in force. The decision establishes the best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for large combustion plants (LCP — combustion installations with a rated thermal input exceeding 50 MW). Plants with a thermal input lower than 50 MW are, however, discussed in the LCP BAT where technically relevant because smaller units can potentially be added to a plant to build one larger installation exceeding 50 MW. In December 2017, the Large Combustion Plant Best Available Technique reference document (LCP BREF) was published. The update of both documents was expected under the Emission Directive and will have a significant implication on the Eni’s technologies applied in the power plants. A Technical Working Group has been formed to implement a new Best Available Techniques Guidance Document on the upstream hydrocarbon exploration and production sector. Moreover, in November, Commission has published its implementing decision establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for the production of large volume organic chemicals (LVOC BAT). New emissions and efficiency standards will help national authorities to lower the environmental impact of the 3,200 installations that produce Large Volume Organic Chemicals (LVOC) and represent 63% of the EU’s entire chemical industry. The Member States must all the permits for LCPs in line with the LCP BAT conclusions by August 2021.

Fluorinated gases (‘F-gases’) play an important role in the accomplishment of the Paris Agreement and in the EU environmental policy. These ozone-depleting substances are regulated by F- gas Regulation (No. 517/2014) which applies from January 1, 2015. The new regulation strengthens the previous measures and should cut by 2030 the EU’s F- gas emissions by two- thirds compared with 2014 levels. This represents a fair and cost-efficient contribution by the F-gas sector to the EU’s objective of cutting its overall GHG emissions by 80 — 95% of 1990 levels by 2050. In 2017, the EU continued to shape the F-gases strategy. In October 2017, the Commission Implementing Decision (EU) 2017/1984 was published in the Official Journal. The decision sets reference values for the period January 1, 2018 to December 31, 2020 for each producer or importer which has lawfully placed on the market hydrofluorocarbons from January 1, 2015 UE of October 24, 2017.

During the reporting year, the EU focused on improving the environmental management principles and rule. In December, the Commission published the decision, amending the user’s guide setting out the steps needed to participate in EMAS (decision 2017/2285). The guidelines offer an additional information and guidance about the steps needed to participate in EMAS (Environmental Management and Audit Scheme recognized by the European Union), which represents the voluntary participation by organizations in a Community eco-management, and audit scheme. In November, Commission Guidelines on

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Environmental Impact Assessment (EIA) were released (they include three parts: Guidance Document on Screening, Guidance Document on Scoping and Guidance Document on the preparation of the EIA Report). The Commission has updated and revised the 2001 EIA Guidance Documents to reflect both the legislative changes brought by 2014/52/EU and the current state of good practice. In February 2018, the working group of experts has started the revision of the ISO 14067 standard that specifies principles, requirements and guidelines for the quantification and communication of the carbon footprint of a product (CFP), based on International Standards on life cycle assessment.

In 2018 the European Parliament and Council approved the directives included in the Circular Economy Package, revising the EU legislation on waste, aiming to stimulate Europe’s transition towards a circular economy. The approved directives introduce new waste-management targets regarding reuse, recycling and landfilling, strengthens provisions on waste prevention and extended producer responsibility, and streamlines definitions, reporting obligations and calculation methods for targets. The July 5, 2020 was the deadline for the Member States to transpose the directives in national legislation. To comply this deadline Italy has published the following decrees in its Official Gazette: Legislative Decree 118/2020 for Waste Batteries and Accumulators and Waste Electrical and Electronic Equipment and Legislative Decree 116/2020 for Waste and Packaging and Legislative Decree 119/2020 for End of Life Vehicles. The new decrees will allow Italy to strengthen its system of extended producer responsibility, stop the generation of waste, define new supply chains and progressively increase the recycling of municipal waste to 65% and reduce the use of landfills to less than 10% by 2035. In January 2018, the first Europe-wide strategy on plastics was adopted. The directive 2019/904/EU was approved on June 2019; it bans some single use plastic products and establishes requirements for some other plastic products (examples: content of recycled plastic, marks on packaging). The directive, which also asks the adoption of measures to strengthen separate collection of plastic waste, must be transposed in national legislations of the Member States by July 3, 2021.

In March 2020 the European Commission adopted a new Circular Economy Action Plan, 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.

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. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees.

On June 1, 2007, the REACH Regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed and caused by chemicals, while enhancing the competitiveness of the EU chemical industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to the European Chemicals Agency (ECHA) how the substance can be safely used and communicate risk management measures to users. If the risks cannot be managed, authorities can restrict the use of substances in different ways. Over time, hazardous substances should be substituted with less dangerous ones. Eni recognizes the importance of the Regulation EC No. 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA which regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspect that concerns the exchange of information between producers and importers, as well as the users of chemical substances (“downstream users”).

The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation EC No. 1272/2008 on the classification, labeling and packaging of substances and mixtures),

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and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them.

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:

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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.

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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.

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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.

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Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation.

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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.

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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.

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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).

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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 Fast Response System (HFRS) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.

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Worldwide Eni approach was to join international consortiums for main equipment and to develop in-house technologies to improve the intervention capability. Eni Emergency Response Kit consists of:

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Outsourced equipment contracted by Eni Head Quarter;

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Access Agreement to Subsea Capping Equipment consortium;

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Access Agreement to Global Dispersant Stockpile consortium;

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Eni Head Quarter proprietary equipment;

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Rapid Cube;

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Killing System.

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:

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technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures;

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expanded public information about risks resulting from Company activities;

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modified rules in participation by the public in land-use planning projects related to Seveso plants; and

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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 2020

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 2020, 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 285, of which:

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92 certifications according to the ISO 14001 standard;

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9 registrations according to the EMAS regulation;

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23 certifications according to the ISO 50001 standard (certification for an energy management system);

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37 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems – requirements) and 61 according to the new ISO 45001 standard;

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41 according to the ISO 9001 standard (certification of the quality management system).

In 2020 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 92% for the OHSAS 18001/ISO 45001 standard and 93% for the ISO 14001 standard.

In 2020, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,286 million (-3% vs 2019).

Environment. In 2020, Eni incurred total expenditures of €942 million for the protection of the environment (with a decrease of 2% with respect to 2019). Environmental expenditures are mainly related to remediation and reclamation activities (€411 million), waste management (€217 million), water management (€153 million), air protection (€54 million) and spill prevention (€33 million).

Safety. Eni is committed to safeguarding the safety of its employees, contractors and all people living in the areas where its activities are conducted and its assets located. In 2018, the new legislation didn’t impact significantly procedures already in place for safety in the workplace.

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In 2020, in order to increase safety culture in the workforce, various projects and initiatives were promoted:

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Human Factor, which mainly concerned:

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the creation of a behavioral analysis model in search of the so-called “weak signals” that provides recommendations to reduce human error , strengthen human “barriers” to counteract the risks of accidents and evaluate the influence of the cultural elements of a given operational reality;

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the creation of an accident investigation methodology to highlight recurring causes;

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the preparation of a new behavioral training course with the aim of promoting greater

awareness of HSE aspects in the context of behavioral safety and of Non Technical Skills.

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Safety starts @ home: with the continuation of smart working the campaign was relaunched and enhanced to promote safety at home starting from the “Safety Golden Rules” 24 – the 10 golden rules for safety at work.

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Development and implementation of digital initiatives to support safety, including the creation of an app to increase HSE culture, initiatives to support the work permit process currently present in over 60 sites and a project to identify recurring danger situations with the support of artificial intelligence.

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Radiation protection, preparation and implementation of a specific program in order to ensure alignment with the requirements of the new Legislative Decree 101/2020, regarding protection from the dangers deriving from exposure to ionizing radiation.

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Product safety: training on the use of the tools: “Safety Data Sheet compliance evaluation” and “scenarious compliance” with the aim of deepening the knowledge of obligations of compliance of the European Norms on chemical substances, strengthening the awareness of the responsibilities and fulfilments of the organizational roles.

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Eni developed the Company Process Safety Management System (PSMS) for increasing the safety of its operations through still higher technical and management standards. In 2019 Eni participated in a working group of EPSC (European Process Safety Center) on the definition of a set of shared operating rules on process safety which led, also through an internal technical team work attended by representatives and knowledge owners of Process Safety of the various Business Units and Operations representatives, to the definition of Eni’s Process Safety Fundamental. In 2020 a massive disclosure of the Process Safety Fundamentals involved transversally Eni’s various businesses, covering approximately 80% of employees of operating sites.

In 2020, the Total Recordable Injury Rate for the workforce worsened by 5% compared to 2019 (0.36 vs 0.34).

Regarding emergency preparedness for oil spills, Eni joined the Oil Spill Response-Joint Industry Project (OSR-JIP I & II), after the Macondo accident ,which was launched in December 2011 by International Association of Oil&Gas Producers (IOGP) and International Petroleum Industry Environmental Conservation Association (IPIECA) and concluded in 2016 . The work of the five-year Joint Industry Project is now included in the Oil Spill Group that continues to develop good practices and facilitates industry forums to share oil spill preparedness and response.

Preparedness and response is regularly tested in exercises. Plans, resources and proper availability of vehicles, vessel and materials are evaluated as well as the incident command system. In order to continuously improve these capabilities, Business Units had almost kept the exercise planning unchanged during pandemic albeit with the appropriate restrictions. A tool for documenting what is known of the situation using the log sheets and brief people, has been developed: the crisis management log-keeper offers a common operating picture for emergency management. Moreover in the same framework Eni participates at two Global Initiatives jointly led by the IMO and IPIECA: OSPRI (Black Sea, Caspian Sea and Central Eurasia) and WACAF (West, Central and Southern Africa).

Costs incurred in 2020 to support the safety levels of operations and to comply with applicable rules and regulations were €291 million.

Health. Eni’s activities for protecting health aim to continuously improve the psychophysical wellbeing of people in the workplace. Eni believes that it achieved a good performance in this area thanks to:

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plant and facility efficiency and reliability;

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promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment;

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certification programs of management systems for production sites and operating units;

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identified indicators in order to monitor exposure to chemical and physical agents;

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strong engagement in health protection for workers operating worldwide also with the support of international health providers capable of guaranteeing a prompt and adequate response to any emergency;

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identification of an effective and reliable health providers, in Italy and abroad;

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training programs for medics and paramedics.

In order to protect the health and safety of its employees, Eni relies on a network of health care facilities located in its main operating areas. A set of international agreements with the best local and international health providers ensures efficient services and timely responses to emergencies.

Eni is engaged to the elaboration of HIA and relative standards to be applied to all new projects of evaluation of working exposure to environment, in Italy and abroad. The main aim of HIA is to avoid any negative impacts and maximize any positive impacts of the project on the host community and it is usually carried out as part of/or in conjunction with the Health, Environmental and a Social Impact Assessment process. Its results are used to develop appropriate mitigation measures and an improvement plan with the host community.

Information about Eni’s strategy and targets in a low-carbon scenario in accordance to standards set by the Task Force on climate-related Financial Disclosures (TCFD) of the Financial Stability Board and other non-financial information about sustainability is provided in the “Non -financial Information report” which is part of Eni’s 2020 Annual Report published in accordance with Italian law and practice. These reports are not incorporated by reference in this Form 20-F.

Regulation of Eni’s businesses

Overview

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

Regulation of exploration and production activities

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

Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any production taxes or royalties, which may be in cash or in-kind. Concession contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production activity. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs

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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 local tax legislation.

Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right.

Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in African, Middle Eastern and Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.

Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. Therefore, the Company recognizes at the same time an increase in the taxable profit, through the increase in revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme to PSA applies to Service contracts.

In general, Eni is required to pay income tax on income generated from production activities (whether under a license or PSA). The taxes imposed upon oil&gas production profits and activities may be substantially higher than those imposed on other businesses.

Regulation of the Italian hydrocarbons industry

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 the property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession, in each case granted by the Minister of Economic Development. 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 field depletes.

These provisions are to be coordinated with a new law effective as of February 12, 2019 (Law 12/2019 — ex “D.L. Semplificazioni”) and further amendment, which requires certain Italian administrative bodies to define and adopt within end September 2021 a plan (PiTESAI) aiming to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, (end September 2021) it is established a moratorium on exploration activities, including the award of new exploration leases.

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Following the plan approval, exploration permits resume their efficacy in areas that have been identified as suitable; on the contrary, in unsuitable areas, exploration permits are repealed. As far as development and production concessions are concerned, pending the national plan approval ongoing concessions retain their efficacy and administrative procedures underway to grant extension to expired concession remain unaffected; instead no applications to obtain new concession can be filed. Once the above mentioned national plan is adopted, development and production concessions that fall in suitable areas can be granted further extensions and applications for new concessions can be filed; on the contrary development and production concessions current at the approval of the national plan that fall in unsuitable areas are repealed at their expiration and no further extensions can be granted, nor new concession applications can be filed. In case Italian administrative bodies fail to adopt the national plan for suitable areas within end September 2021, the general moratorium on exploration activities is revoked and application for new concession permits can be filed. According to the statute, areas that suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline.

Moreover, the above mentioned law, starting from June 1, 2019, increases by 25 fold the current annual fee for all licensees (exploration permits and production concessions).

Finally, it’s worth to mention two further legislative measures recently approved:

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the Fiscal decree no. 124/2019, converted into Law 157/2019which established (art. 38), starting from 2020, the property tax on marine structures (IMPI);

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the Law 21/2021 – “D.L. Milleproroghe” which extends the time required for definition and adoption of PiTESAI until end September 2021) as well as the moratorium for prospecting and research.

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

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:

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Market based mechanisms for the allocation of storage capacities and of regasification capacities: moving away from the traditional 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 recently to the country.

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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.

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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).

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 oil-based indexation and spot prices.

This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed.

This new gas tariff indexation aiming at safeguarding the households was initially intended to remain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year (as per Law Decree 91/2018), and finally has been prorogated to January 1, 2023. From that point onwards, households in Italy 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. 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.

In the electricity market the regulated prices phase out will be effective: from January 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) and from January 1, 2023 for households and microenterprises (enterprise which employs fewer than 10 persons and whose annual turnover and/or annual balance sheet total does not exceed €2 million).

Other regulatory developments in the gas and electric sector in Italy and Europe

Within the scope of access criteria to the main gas logistic infrastructures, and of the related access costs, the risk factors for the business are linked to the periodic processes by which each European country reviews the definition of economic conditions and access rules for transportation, LNG regasification and storage services. Concerning gas transportation tariffs, last year the criteria for gas transportation tariffs were re-defined for the next regulatory periods (2020-2023) in Italy and in most European countries where Eni operates and the outcome of such process brought some improvements in our portfolio’s logistic costs. The re-definition of transportation tariffs criteria occurs periodically and may always determine some impact on our logistic costs.

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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 and, in some countries, also by the envisaged phase out of nuclear power generation. On the other side, with the implementation of the EU Green Deal, in the medium term we could expect changes in the gas sector regulation, due to the need to adapt the European market design to the challenges of the energy transition and of the decarbonisation targets (i.e. development of renewable and decarbonized gases, growth of new technologies enabling a stronger integration between the gas and the electricity sectors). These changes will likely bring pressures 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, allocated capacity with delivery in 2022 and 2023 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 balancing market (the so called “MSD”) 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 and 2023) and for a new power plant, that will be built in Ravenna, for a period of fifteen years (starting from 1.1.2023). This benefit is affected by the risk that the tenders could be canceled due to the administrative appeal filed by some power companies against the tender procedure.

In the second half of 2020, Italian Government has started the process for the extension of Capacity Market that, if finally approved, it will stabilize the revenue of power generation from gas after 2023. Due to the pending process, the timeline and the auctions procedure are far to be defined and their definition is marked by a level of uncertainty.

Besides, in the next years Italian power market design could significantly change due to the implementation of European market model. The main innovations concern: introduction of negative prices, starting of new intraday Market based on continuous trading and gate-closure close to delivery period (h -1 gate closure), fostering the cross-border integration of European energy and balancing market (coupling of intraday market, coupling of balancing reserves markets). Management believes that this development will increase competition, in particular in the Italian balancing market.

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 that defined mineral oil processing and storage plants as “strategic installations” that need authorization from the State, in agreement with the local administrations. The Decree introduced a unitized process of authorization that must be finalized within 180 days, subject to compliance with applicable environmental regulations. the company has not experienced any material delays in obtaining relevant concessions for the upgrading of the Sannazzaro underway.

Marketing. Following the enactment of the above-mentioned Law Decree No. 1 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. 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 will be allowed to freely supply up to 50% of their requirements. In such case, the distributing company will 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 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.

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.

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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 city 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.

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.

The 2021 budget law (Law 178/2020) introduced the obligations for concessionaires’ highway stations to provide electric charging points (power 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 recognised by local authorities (i.e. tax reduction or exemption for public land use).

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.

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

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 to 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 measure aims to favor advanced biofuels production through the valorization of waste, notably of agricultural and farm/zoo technical waste.

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).

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Law no. 128/2019 anticipated the transposition of the EU regulation on End of Waste and the authorization stall has been unlocked. Italian Regions can now authorize the recycling and recovery systems “on a case-by-case basis”, pending the adoption of the regulations on individual processes.

The Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources confirms the use of some wastes as feedstock for the production of biofuels and allows the calculation of recycled carbon fuels for the purposes of the transport target, based on the criteria that will be issued by the European Commission. The directive must be transposed by June 30, 2021.

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 fuel retail market. These regulatory initiatives will also address for more competition and efficiency of the sector.

With 2021 budget law and other several Acts (Law Decree 34/2020 and 104/2020), 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.

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 for Economic Development 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, 2020, Eni owned 5.2 mmtonnes of oil products inventories, of which 3.4 mmtonnes as “compulsory stocks”, 1.6 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.2 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (32%), light and medium distillates (32%), refinery feedstock (22%), fuel oil (8%) and other products (6%) were located throughout the Italian territory both in refineries (87%) and in storage sites (13%).

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

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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, 2020, there were 233 subsidiaries and 116 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, 2020 is provided in the notes to the Consolidated Financial Statements.

Item 4A. UNRESOLVED STAFF COMMENTS

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Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Key Information presented in Item 3 and 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.

Executive summary

IMPACTS OF the COVID-19 PANDEMIC

The trading environment in 2020 saw the largest oil demand drop in history according to external, independent sources (i.e. the IEA who estimated a contraction of 9% as compared to the prior year). This reduction was driven by the lockdown measures implemented at global scale to contain the spread of the COVID-19 pandemic causing a material hit to economic activity, international commerce and travel, mainly during the peak of the crisis in the first and second quarter of 2020.

The shock in hydrocarbon demand occurred against the backdrop of a structurally oversupplied oil market, as highlighted by the disagreements among OPEC+ members in the response to be adopted to manage the crisis in early March 2020. The producing countries of the cartel decided against maintaining the existing quotas and as a result the market was inundated with production while demand was crumbling. Those developments led to a collapse in commodity prices. At the peak of the downturn, between March and April, the Brent marker price fell to about 15 $/barrel, the lowest level in over twenty years. The oversupply drove oil markets into contango, a situation when prices for prompt delivery quote below prices for future deliveries, while both land and floating storages reached the highest technical filling levels.

Since May, oil prices have been staging a turnaround thanks to a comprehensive agreement reached within OPEC+ on implementing record production cuts as well as to an ongoing recovery in the world economy and oil consumption following an ease in restrictive measures and driven in large part by a strong rebound of activity in China. Brent prices recovered to almost 45 $/barrel in the summer months.

However, during the autumn months, the macroeconomic rebound hit a standstill in the United States and in Europe due to a resurgence in virus cases, which forced governments and local authorities in those countries to reinstate partial or full lockdowns and other restrictive measures that weighed heavily on oil and products demands as millions of people continued living in partial isolation. In this period, crude oil prices held the 40-$ mark, because they were supported by strict production discipline on part of OPEC+ members and the market was able to accommodate the return of Libya’s production by the end of September, which quickly ramped to the plateau of 1.2 million boe/d as a result of an internal peace agreements which resolved the force majeure which had blocked export terminals. A barometer of the weakness of the fundamentals in the energy sector in the third and fourth quarter was the trend in the refining margins which dropped to historic lows due to weak demand for fuels and the crisis in the airline sector, which prevented refiners from passing the cost of the crude oil feedstock to the final prices of products. To make things worse, OPEC+ production cuts impacted the availability of medium-heavy crudes, narrowing the price differentials with light-medium qualities like Brent crude and squeezing the refiners’ conversion advantage.

However, since mid-November a few market and macroeconomic developments triggered a rally in oil prices, which reached 50 $/bbl at the end of the year and then rose to an average of more than 60 $/barrel in the first quarter of 2021, having touched prices as high as 70 $/bbl. First, several effective vaccines against the virus were approved. Second, the OPEC+ members resolved at a meeting in early December to slowdown the pace of easing the production curtailments scheduled to begin at the onset of 2021. Then in a subsequent meeting in early January 2021, KSA surprised markets by announcing a unilateral cut to its production quota of 1 million barrels/d in February and March in relation to the uncertainties to the recovery in demand caused by the ongoing rise in new virus cases. Meanwhile, the pace of the economic recovery accelerated in Asia, where China and India drove a surge in oil consumption. The new administration in the United States approved large fiscal measures to spur economic growth. The inventory overhang began to ease due to the market being better balanced. Finally, exceptional cold weather

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conditions hit the Far East which caused a mini energy crisis due to the sudden spike in the demand for heating products which led to a substantial increase in the JKM benchmark spot prices of LNG which climbed to all-time highs, up to 30-40 $/mmbtu (an increase more than 1000% compared to the values recorded in April 2020 during the peak of the crisis).

Despite these positive developments, we believe the outlook for 2021 to remain uncertain and volatile due to an ongoing slowdown in economic activity and in oil consumption in Europe and in the United States, with possible downside risks related to the evolution of the pandemic crisis and the discovery of new virus strains.

In 2020 due to the macroeconomic and market developments described above, the average price of the Brent benchmark crude oil decreased by 35% compared to the previous year, with an annual average price of 42 $/barrel; the price of natural gas at the Italian spot market “PSV” declined on average by 35%, and the Standard Eni Refining Margin – SERM recorded the worst performance among our external indicators (down by 60%). Considering the market trends, management revised the Company’s outlook for hydrocarbon prices assuming a more conservative oil scenario with a long-term Brent price at 60 $/barrel in 2023 real terms (compared to the previous projection of 70 $/barrel) to reflect the possibility of a prolonged period of weak oil demand the risk that the energy transition will accelerate due to the fiscal policies adopted by governments to rebuild the economy on more sustainable basis. These developments had negative, material effects on Eni’s results of operations and cash flow.

In 2020, Eni Group reported a net loss of €8.64 billion due to lower realized prices for equity hydrocarbons and lower refining margins with an estimated impact of €6.8 billion and lower production volumes and other business impacts caused by the COVID-19 pandemic for €1 billion, as well as the recognition of impairment losses of €3.2 billion taken at oil&gas assets and refineries due to management’s revised outlook on long-term oil and gas prices and lowered assumptions for the refining margins. A loss of approximately €1.3 billion was incurred in relation to the evaluation of inventories of oil and products which were aligned to their net realizable values at period end. Cost efficiencies and other management initiatives to counter the effects of the pandemic drove an improvement of €1.1 billion. Furthermore, the Group net loss for the year was also due to a €1.66 billion loss taken at equity-accounted investments, to a €1.3 billion loss for the write-down of deferred tax assets due to the projections of lowered future taxable profits and the negative effects on the underlying tax rate of the recognition of non-deductible losses and charges, the inability to recognize deferred tax assets on losses for the year in jurisdictions with the projection of lower future taxable income and other non-deductible items.

Net cash provided by operating activities amounted to €4.8 billion with a reduction of €7.6 billion or 61% compared to 2019, due to lower prices of hydrocarbons and other scenario effects for €6.8 billion and the negative impact on operations associated with COVID-19 for €1.3 billion due to lower production as a result of the curtailment of expenditures, OPEC+ cuts and lower demand for equity gas, lower demand for fuel and chemicals, longer maintenance standstills in response to the COVID-19 emergency, lower LNG offtakes in Asia and lower gas demand in Europe and higher provisions for impairment losses at trade receivables. These negatives were partially offset by cash savings and other initiatives in response to the pandemic crisis for an amount of €0.5 billion.

In order to respond to a shortfall of such magnitude, management has taken several decisive actions to preserve the Company’s liquidity, the ability to cover maturing financial obligations and to mitigate the impact of the crisis on the Group’s net financial position and profitability, as follows:

•

Capital expenditures (“capex”) for 2020 were 35% lower than the initial capital budget excluding currency effects, with a saving of €2.6 billion. Those capex reductions mainly related to upstream activities, targeting production optimization activities and the rephasing of certain development projects, which negatively affected production volumes. The delayed or re-phased activities can be recovered once the scenario normalizes, determining a recovery of related production.

•

In May 2020, a €2 billion bond was issued. Then, in October 2020, two hybrid bonds were issued for a total amount of €3 billion; those latter bonds were classified as equity for balance sheet purposes.

•

A share repurchase program approved before the start of the crisis was put on hold. It is expected to resume in 2021 conditioned on a stable improvement in the scenario.

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threshold has been revised to 43 $/bbl) and a growing variable component in the event of a recovery in the crude oil scenario. The floor amount will be revalued over time depending on the Company delivering on its industrial targets. For 2020, the dividend proposal is equal to the floor dividend, notwithstanding the annual average Brent price of 42 $/barrel being lower than the threshold. One third of the floor dividend was paid as an interim dividend in September 2020.

The Company, leveraging on these measures, successfully overcame the worst phase of the downturn, limiting the increase in the borrowings – i.e. total finance debt less cash and cash equivalent and held-for trading securities as defined in our Glossary – which closed the year at €11.57 billion (ante IFRS 16 or €16.59 billion including IFRS 16), little changed over 2019. See the paragraph “Financial conditions” below. To fulfill the financial obligations coming due in the short-term the Company can count on a liquidity reserve of €20.4 billion as of December 31, 2020, consisting of:

•

cash and cash equivalents of €9.4 billion;

•

€5.3 billion of undrawn committed borrowing facilities;

•

€5.5 billion of readily disposable securities (mainly government bonds and corporate investment grade bonds) and €0.2 billion of short-term financing receivables.

This reserve is considered adequate to cover the main financial obligations maturing in the next twelve months relating to:

•

short-term debt of €2.9 billion;

•

maturing bonds of €1.1 billion and other maturing long-term debt of €1.1 billion;

•

committed investments of €4.3 billion;

•

instalments of leasing contracts coming due of €1.1 billion;

•

the payment of a floor dividend for approximately €1.5 billion (including the final 2020 dividend and the interim floor dividend for fiscal year 2021 due to be paid in September 2021).

The evolution of the Group’s financial situation in 2021 will depend, in addition to management initiatives, on trends in oil prices, which will be closely correlated to the evolution of the pandemic crisis. The short-term recovery of the crude oil and gas prices will greatly depend on how the current COVID-19 crisis unfolds and on how long it lasts. Under adverse assumptions, the spread of the disease could dampen or further delay an economic recovery, which could materially hit demand for energy products and prices of energy commodities.

This scenario could be further complicated in case of a faltering OPEC+ policy at supporting prices by continuing to roll over the ongoing production quotas. These trends could have a material and adverse effect on our results of operations, cash flow, liquidity, and business prospects, including trends in Eni shares and shareholders’ returns.

Considering the risks and uncertainties associated with the trading environment, we are retaining a disciplined and selective approach to investment decisions and we expect to limit our expenditures to an amount of slightly less than €7 billion per year on average in the next four-year plan 2021-2024, which will be dedicated to maintain production, to develop our pipeline of oil&gas growth projects and to expand the businesses of the energy transition. For 2021, we expect to make capital expenditures of less than €6 billion and to maintain production level flat as compared to the prior year, assuming OPEC+ cuts of about 40 kboe/d in the year. See the paragraph “Management expectations of operations” below. We forecast a crude oil price for the Brent benchmark at 50 $/bbl in 2021 and a standard Eni’ refining margins “SERM” of 3.8 $/bbl (see below and also Glossary for a definition of SERM which is a gauge of profitability of the R&M oil-based refining business), under which assumption we plan to generate enough cash flow from operations to fund our expected organic capital expenditures (i.e. excluding acquisitions) for the year, as well as to cover a portion of the floor dividend. Our cash flow is subject to the volatility of the energy scenario.

Considering the current oil&gas assets portfolio, management has estimated a change of cash flow of approximately €150 million for each one-dollar change in the price of the Brent crude oil benchmark and proportional changes in gas prices, compared to the considered scenario for 2021 at 50 $/barrel, excluding the effects on the dividends from investments. The Brent crude oil prices have been trending higher in the first quarter of 2021, averaging more than 60 $/bl. However, this positive trend will be partly offset by lower refining margins which during this period have tracked well below our expectations, having recorded a

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negative value in this period driven by high costs of oil-based feedstock and weak refined products prices due to continued weakness in demand for fuels. We are currently estimating a change of cash flow of approximately €160 million per each one-dollar change in the SERM compared to the assumption for 2021 of $3.8 per barrel.

Eni’s new organizational structure and segment reporting

Effective July 1, 2020, Eni’s management redesigned the macro-organizational structure of the Group, in line with its new long-term strategy aimed at transforming the Company into a leader in the production and marketing of decarbonized energy products.

The new organization is based on two new business groups:

•

Natural Resources, to build up 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 will focus its actions on the development of carbon capture and compensation projects. The business group will incorporate the Company’s oil & gas exploration, development and production activities, natural gas wholesale via pipeline and LNG. In addition, it will include forests conservation (REDD+) and carbon storage projects. Eni Rewind, Eni’s environmental company, will also be included in this business Group.

•

Energy Evolution will focus on the evolution of the businesses of power generation, transformation and marketing of products from fossil to bio, blue and green. In particular, it will focus on growing power generation from renewable energy and biomethane, it will coordinate the bio and circular evolution of the Company’s refining system and chemical business, and it will further develop Eni’s retail portfolio, providing increasingly more decarbonized products for mobility, household consumption and small enterprises. The business group will incorporate the activities of power generation from natural gas and renewables, the refining and chemicals businesses, Retail Gas&Power and mobility marketing. The subsidiaries Versalis (chemical products) and Eni gas e luce will be consolidated in this business Group.

The new organization represents a fundamental step to implement Eni’s strategy to become leader in the supply of decarbonized products by 2050 combining value creation, sustainability, and financial resilience.

In re-designing the Group’s segment information for financial reporting purposes, management evaluated that the components of the Company whose operating results are regularly reviewed by the Chief Operating Decision Maker (CEO) to make decisions about the allocation of resources and to assess performances would continue to be the single business units which are comprised in the two newly-established business groups, 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 new reportable segments of Eni, substantially confirming the pre-existing setup, are identified as follows:

•

Exploration & Production: research, development and production of oil, condensates and natural gas, forestry conservation (REDD+) and CO2 capture and storage projects.

•

Global Gas and LNG Portfolio: supply and sale of wholesale natural gas by 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 optimizing the gas asset portfolio. In prior reporting periods, this segment also included the results of operation of the trading business of oil and refined products that in 2020 was reallocated to the Refining &Marketing business.

•

Refining & Marketing and Chemicals: supply, processing, distribution and marketing of fuels and chemicals. The results of the Chemicals segment were aggregated with the Refining & Marketing performance in a single reportable segment, because these two operating segments have similar economic returns. It comprises the activities of trading oil and products with the aim to execute the transactions on the market in order to balance the supply and stabilize and cover the commercial margins. This latter activity was previously reported in the G&P segment in 2019 and 2018. Therefore, the comparative results of the R&M business have been restated.

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•

Eni gas e luce, Power & Renewables: retail sales of gas, electricity and related services, production and wholesale sales of electricity from thermoelectric and renewable plants. It includes trading activities of CO2 emission certificates and forward sale of electricity with a view to hedging/optimizing the margins of the electricity. In prior reporting periods, the results of operations of Eni gas e luce and of the power business were reported within the Global Gas and LNG portfolio (formerly named Gas&Power). In prior reporting periods, Results of operations of the business renewables were reported within the Corporate and other activities group, because they were immaterial.

•

Corporate and Other activities: includes the main business support functions, in particular financial services, central treasury, IT, human resources, real estate services, captive insurance activities, research and development, new technologies, business digitalization and the environmental activity developed by the subsidiary Eni Rewind.

According to the requirements of IFRS 8, the new Eni information segment has been effective since January 1, 2020; therefore, the results for the full year comparative periods 2019 and 2018 have been restated to adjust them to the change of the segment information, as follows:

	2019				2018
	As published		As restated		As published		As restated
Sales from operations		69,881		69,881		75,822		75,822
E&P		23,572		23,572		25,744		25,744
G&P		50,015				55,690
Global Gas and LNG Portfolio				11,779				14,807
Refining & Marketing and Chemicals		23,334		42,360		25,216		46,483
EGL, Power & Renewables				8,448				8,218
Corporate and other activities		1,681		1,676		1,589		1,588
Impact of unrealized intragroup profit elimination and other consolidation adjustments		(28,721)		(17,954)		(32,417)		(21,018)

	2019				2018
	As published		As restated		As published		As restated
Operating profit (loss)		6,432		6,432		9,983		9,983
E&P		7,417		7,417		10,214		10,214
G&P		699				629
Global Gas and LNG Portfolio				431				387
Refining & Marketing and Chemicals		(854)		(682)		(380)		(501)
EGL, Power & Renewables				74				340
Corporate and other activities		(710)		(688)		(691)		(668)
Impact of unrealized intragroup profit elimination and other consolidation adjustments		(120)		(120)		211		211

	2019				2018
	As published		As restated		As published		As restated
Adjusted operating profit (loss)		8,597		8,597		11,240		11,240
E&P		8,640		8,640		10,850		10,850
G&P		585				543
Global Gas & LNG Portfolio				193				278
Refining & Marketing and Chemicals		21		21		380		360
EGL, Power & Renewables				370				262
Corporate and other activities		(624)		(602)		(606)		(583)
Impact of unrealized intragroup profit elimination and other consolidation adjustments		(25)		(25)		73		73

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The adjusted operating profit for each segment disclosed above is a NON-GAAP measure of financial performance and is commented below.

2020 RESULTS OF OPERATIONS AND CASH FLOW

Key consolidated financial data

		2020		2019		2018
		(€ million)
Sales from operations			43,987		69,881		75,822
Operating profit (loss)			(3,275)		6,432		9,983
Net profit (loss) attributable to Eni			(8,635)		148		4,126
Net cash provided by operating activities			4,822		12,392		13,647
Capital expenditures			4,644		8,376		9,119
Acquisitions			392		3,008		244
Disposal of assets, consolidated subsidiaries and businesses			28		504		1,242
Shareholders’ equity including non-controlling interest			37,493		47,900		51,073
Finance debt (including lease liabilities)			31,704		30,166		25,865
Net borrowings excluding lease liabilities(1)			11,568		11,477		8,289
Net profit (loss) attributable to Eni basic and diluted	(€ per share)		(2.42)		0.04		1.15
Dividend per share	(€ per share)		0.36		0.86		0.83
Ratio of finance debt (including lease liabilities) to total shareholders’ equity			0.84		0.63		0.51
Ratio of net borrowings excluding lease liabilities to total shareholders’ equity (leverage)(1)			0.31		0.24		0.16

(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 – “Liquidity and capital resources – Financial Conditions” below.

Reported earnings

In 2020, Eni reported a net loss attributable to its shareholders of €8,635 million, driven by an operating loss of €3,275 million, as well as significantly lower income from investments.

The 2020 results were materially and negatively affected by a challenging operating and trading environment due to the economic crisis related to the COVID-19 pandemic, which caused a massive reduction in demands and prices for crude oil and other Company’s products. Furthermore, the operating loss was negatively affected by the recognition of impairment losses of €3.2 billion mainly taken at oil&gas assets and refineries. Falling oil and product prices negatively affected inventory valuation, which were aligned to their net realizable values at period end (resulting in an operating charge of €1.3 billion).

Net result for the year was also negatively affected by lower net income from investments (down by €1,658 million) affected by the same market and industrial trends as operated activities, as well as by impairment losses of tangible assets and inventory valuation allowance. These losses related to Eni’s share of the results of equity accounted entities, mainly attributable to the Vår Energi joint venture as well as to ADNOC Refining associate and Saipem joint venture.

Finally, the net result was negatively affected by the write-off of deferred tax assets driven by projections of lower future taxable income (€1.3 billion).

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 non-core 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 be useful to an investor 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,

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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 2020, non-core items included impairment losses, risk and environmental provisions, extraordinary credit losses, the accounting effect of certain fair-valued commodity derivatives lacking the formal criteria to be classified as hedges or to be eligible for the own use exemption and other non-core charges for a total negative of €7,877 million in net profit and of €5,173 million in operating profit, including an inventory pre-tax loss of €1,318 million (€937 million post-tax).

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

	Year ended December 31,
Eni Group	2020		2019		2018
	(€ million)
(Profit) loss on inventory		1,318		(223)		96
Environmental provisions		(25)		338		325
Impairment losses (impairments reversals), net		3,183		2,188		866
Net gains on disposal of assets		(9)		(151)		(452)
Risk provisions		149		3		380
Provision for redundancy incentives		123		45		155
Reinstatement of Eni Norge amortization charges(1)						(375)
Fair value gains/losses on commodity derivatives		440		(439)		(133)
Reclassification of currency derivatives and exchange effects to management measure of business performance		(160)		108		107
Credit valuation allowance(2)		77		123
Compensation gain on part of a third-party insurer relating to the EST plant incident				(88)
Other		77		261		288
Total net non-core items in operating profit		5,173		2,165		1,257
Finance expenses		152		(42)		(85)
of which: reclassification of currency derivatives and exchange effects to management measure of business performance		160		(108)		(107)
Capital gains on disposal of investments				(46)		(909)
Write downs of investments and financing receivables		1,207		166		67
Write down of deferred tax assets/utilization of deferred tax liabilities		1,299		893		99
Tax effects on the above listed items and other items		427		(474)		55
Tax effects on (profit) loss on inventory		(381)		66		(27)
Net non-core items in net profit		7,877		2,728		457

(1)

In 2018, management has evaluated to reinstate correlation between hydrocarbon production and reserve depletion by accruing the underlying UOP-based amortization charges of Eni Norge subsidiary classified in accordance to IFRS 5 due to the business combination with Point Resources. In the GAAP results, assets or disposal group held for sale are not to be depreciated or amortized.

(2)

In 2020 and 2019, this item relates to credit losses recognized in connection with the renegotiation of a petroleum contract.

The Group underlying performance – i.e. excluding non-core losses and the inventory holding loss – was an adjusted operating profit of €1,898 million compared to €8,597 million in 2019, down by 78% or by €6.7 billion. The decrease in adjusted operating profit was driven by lower results in the E&P segment (down by €7.1 billion) and in the Refining & Marketing and Chemical segment (down by €0.02 billion), partly offset by the increase in the Global Gas and LNG Portfolio segment (up by €0.13 billion) and the Eni gas e luce, Power & Renewables segment (up by €0.10 billion). The main reasons for the decline were:

•

Significantly lower prices and margins of the products that we produced and sold, which negatively impacted the performance for about €6.8 billion, mainly in the E&P segment due to lower realized prices for equity production of oil and natural gas as well as lower refining margins;

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•

The impact of COVID-19 pandemic amounting to €1 billion which comprised a reduction in hydrocarbon production due to capex cuts, the need to comply with OPEC+ quotas and lower global gas demand, lower LNG offtakes in Asia, lower production and sales volumes in R&M, higher allowances for doubtful accounts and other business impacts.

These negative trends were partly offset by a number of positive drivers as a result of management’s initiatives to cope with the downturn. These initiatives included cost cutting measures, better results earned at our retail gas and power businesses due to increased non-commodity revenues and an expansion of the customers portfolio, an increased performance achieved in the Global Gas and LNG Portfolio business which leveraged its gas assets to benefit from market volatility, a positive result of the bio-refineries due to higher volumes processed and higher margins and in the marketing of refined products due to better efficiency and lower expenses. Management estimated that the Group internal performance increased operating profit by €1.1 billion, partly offsetting the negativity of the trading environment.

Excluding non-core items and the inventory evaluation profit, adjusted net loss for 2020 was €758 million, a €3.63 billion decrease compared to 2019. The result was negatively affected, in addition to a lower operating performance, by lower income from JV and other industrial investments due to the deteriorated macroeconomic framework. Furthermore, net loss reflected an increased Group tax rate due to a depressed trading environment which limited the Company’s ability to recognize deferred tax assets for current losses and other factors.

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,
	2020		2019		2018
	(€ million)
Operating profit (GAAP measure)		(3,275)		6,432		9,983
Inventory holding (gains) and losses		1,318		(223)		96
Identified net (gains) losses		3,855		2,388		1,161
Total net non-core items in operating profit		5,173		2,165		1,257
Adjusted operating profit (Non-GAAP measure)		1,898		8,597		11,240
Net profit (GAAP measure)		(8,635)		148		4,126
Inventory holding (gains) and losses, post tax		937		(157)		69
Identified net (gains) losses, post tax		6,940		2,885		388
Total net non-core items in net profit		7,877		2,728		457
Adjusted net profit (Non-GAAP measure)		(758)		2,876		4,583

In 2020, the Group’s net cash provided by operating activities was €4,822 million, €7,570 million lower than in 2019 or down 61%, due to a significantly deteriorated trading environment, which also negatively affected the results of our equity-accounted entities and their ability to pay dividends to us, which were lower than in 2019 (€509 million in 2020 versus €1,346 million in 2019).

Capital expenditure and acquisitions amounted to €5,036 million, of which capital expenditure were €4,644 million, a 45% reduction from 2019, reflecting the curtailments implemented by management following a review of the industrial plan 2020-2021 in response to the COVID-19 pandemic crisis. These curtailments mainly affected the development of hydrocarbon reserves.

Other investing activities absorbed €0.74 billion of cash. Repayments of lease liabilities were €0.87 billion, while positive exchange rate differences on finance debt amounted to €0.76 billion.

Cash returns to Eni shareholders were €1,965 million and included the payment of the final 2019 dividend and the interim 2020 dividend. The execution of a stock repurchase plan was suspended in March 2020 due to the deteriorated trading environment. It is expected to resume in 2021 conditioned upon a recovery in crude oil prices.

These cash outflows were offset by the issuance of two hybrid bonds amounting to €3 billion leaving net borrowings substantially unchanged at year-end. Management evaluates the soundness of the Group balance sheet and its financial position by monitoring a non-GAAP measure of indebtedness, net borrowings, which is calculated by subtracting cash and cash equivalents and other very liquid financial assets from finance debt (see Glossary), before the accounting effects of IFRS 16.

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Our ratio of indebtedness – leverage – ratio of net borrowings before IFRS 16 to total equity, which is a non-GAAP measure was 0.31 at year-end 2020 (compared to 0.24 at year-end 2019) and was in line with management’s expectations. The corresponding GAAP measure (ratio of total finance debt to total equity) was 0.84, compared to 0.63 at year-end.

See paragraph “Financial condition” below, for a full reconciliation of net borrowings and leverage to the most comparable performance measures calculated in accordance with IFRS.

Trading environment


	2020		2019		2018
Average price of Brent dated crude oil in U.S. dollars(1)		41.67		64.30		71.04
Average price of Brent dated crude oil in euro(2)		36.49		57.44		60.15
Average EUR/USD exchange rate(3)		1.142		1.119		1.181
Standard Eni Refining Margin (SERM)(4)		1.7		4.3		3.7
Euribor – three month euro rate %(3)		(0.43)		(0.36)		(0.32)

(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.

Eni’s results of operations and the year-to-year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. See “Item 3 – Risk factors” for a description of the main trends which characterized the year 2020.

The movement of the USD vs the Euro did not affect results of operation and cash flow in 2020 in a significant way; however the depreciation of the USD in the final part of 2020 drove a significant reduction of the consolidated net assets which negatively affected the Group leverage (by about 2 basis points).

Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the carrying amounts of assets and liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience or 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 assets, specifically in the determination of proved and proved developed reserves and impairment of fixed assets. Other areas where management’s estimates and judgement are applied include, among others, evaluation and recognition of intangible assets, equity-accounted investments and goodwill, decommissioning and restoration liabilities, business combinations, pensions and other post-retirement benefits, environmental liabilities and lease contracts. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A review of significant accounting estimates and judgmental areas is provided in “Item 18 – Note 1 to Consolidated Financial Statements”.

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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 2019 Group results compared to 2018, see the Annual Report on Form 20-F 2019, filed to the SEC on April 2, 2020.

	Year ended December 31,
	2020		2019		2018
	(€ million)
Sales from operations		43,987		69,881		75,822
Other income and revenues(1)		960		1,160		1,116
Total revenues		44,947		71,041		76,938
Operating expenses		(36,640)		(54,302)		(59,130)
Other operating (expense) income		(766)		287		129
Depreciation, depletion and amortization		(7,304)		(8,106)		(6,988)
Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net		(3,183)		(2,188)		(866)
Write-off of tangible and intangible assets		(329)		(300)		(100)
OPERATING PROFIT (LOSS)		(3,275)		6,432		9,983
Finance income (expense)		(1,045)		(879)		(971)
Income (expense) from investments		(1,658)		193		1,095
PROFIT (LOSS) BEFORE INCOME TAXES		(5,978)		5,746		10,107
Income taxes		(2,650)		(5,591)		(5,970)
Net profit (loss)		(8,628)		155		4,137
Attributable to:
– Eni’s shareholders		(8,635)		148		4,126
– Non-controlling interest		7		7		11

(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,
	2020		2019		2018
	(€ million)
Exploration & Production		13,590		23,572		25,744
Global Gas & LNG Portfolio		7,051		11,779		14,807
Refining & Marketing and Chemicals		25,340		42,360		46,483
Eni gas e luce, Power & Renewables		7,536		8,448		8,218
Corporate and other activities		1,559		1,676		1,588
Consolidation adjustments		(11,089)		(17,954)		(21,018)
SALES FROM OPERATIONS		43,987		69,881		75,822

2020 compared to 2019. Eni sales from operations (revenues) for 2020 (€43,987 million) decreased by €25,894 million from 2019 (or down by 37.1%) primarily reflecting the drop in commodity prices and lower sales volumes of our products.

Revenues generated by the Exploration & Production segment (€13,590 million) decreased by €9,982 million (or down by 42.3%) driven by lower average realizations on equity hydrocarbons (oil realizations were down by 37.5%; gas realizations were down by 23.9% on average in dollar terms, see

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Item 4) due to lower prices for the Brent crude oil benchmark (down by 35.2% or 22.6 $/bbl) and lower gas benchmark prices in Europe (down by 16 € per thousand cubic meters, or 35% with reference to the Italian benchmark spot price). Furthermore, revenues were reduced as result of lower equity production of hydrocarbons due to the effects of reduced capital expenditures to develop hydrocarbons reserves and to the need to comply with the production quotas enacted by the OPEC+ nations, as well as lower gas offtakes at our fields in Egypt due to a gas demand downturn.

Revenues generated by the Global Gas & LNG Portfolio (€7,051 million) decreased by €4,728 million (or down by 40.1%). The decrease reflected lower natural gas prices and, to a lesser extent, reduced volumes due to a contraction in gas demand in the main European markets affected by the COVID-19 pandemic, mainly in the second quarter of 2020, being the height of the crisis.

Revenues generated by the Refining & Marketing and Chemical segment (€25,340 million) decreased by €17,020 million (or down by 40.2%) due to lower product prices and, to a lesser extent, lower commodities demand driving a fall in sales volumes.

Revenues generated by the Eni gas e luce, Power & Renewables segment (€7,536 million) decreased by €912 million (or down by 10.8%) due to lower natural gas and power prices due to the trends in the energy environment.

Other income and revenues

2020 compared to 2019. Eni’s other income and revenues amounted to €960 million in 2020 and mainly related to the share of lease repayments debited to joint operators in Eni-led upstream projects (€357 million).

b) Operating expenses

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

	Year ended December 31,
	2020		2019		2018
	(€ million)
Purchases, services and other		33,551		50,874		55,622
Impairment losses (impairment reversals) of trade and other receivables, net		226		432		415
Payroll and related costs		2,863		2,996		3,093
Operating expenses		36,640		54,302		59,130

2020 compared to 2019. Operating expenses for 2020 (€36,640 million) decreased by €17,662 million compared to the prior year, down by 32,5%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale due to lower prevailing market prices). Furthermore, expenses were reduced due to widespread cost reduction initiatives across all businesses implemented by management to preserve the Company’s liquidity with achieved savings of about €1.9, of which about 30% are of structural nature, and mainly related to the purchase of services from third parties in the IT and industrial and business-support activities. Payroll and related costs (€2,863 million) decreased by €133 million from 2019, down by 4.4%, mainly due to a decrease in the average number of employees compared to the prior year, mainly outside Italy, and the appreciation of the euro against the U.S. dollar, partly offset by higher provisions for redundancy incentives.

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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,
	2020		2019		2018
	(€ million)
Exploration & Production		6,273		7,060		6,152
Global Gas & LNG Portfolio		125		124		226
Refining & Marketing and Chemicals		575		620		399
Eni gas e luce, Power & Renewables		217		190		182
Corporate and other activities and impact of unrealized intragroup profit elimination		114		112		29
Total depreciation, depletion and amortization		7,304		8,106		6,988
Impairment losses (impairment reversals) of tangible and intangible assets, goodwill and right of use assets, net		3,183		2,188		866
Write-off of tangible and intangible assets		329		300		100
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		10,816		10,594		7,954

2020 compared to 2019. In 2020, depreciation, depletion and amortization charges (€7,304 million) decreased by €802 million from 2019, mainly in the Exploration & Production segment (a decrease of €787 million) mainly due to capex reductions and lower production, as well as lower book values of oil&gas assets following the impairment losses recorded in the interim reporting periods of 2020.

In 2020, the Group recorded impairment losses at property, plant and equipment for a total amount of €3,183 million, mainly relating to: (i) oil&gas properties (€1,888 million) in production or under development, driven by a downward revision to management’s expectations for crude oil prices in the long-term, which were reduced to 60 $/barrel and the associated curtailments of expenditures in the years 2020-2021 with the re-phasing of a number of projects, in order to preserve cash generation, as well as negative revisions of reserves. The main impairment losses were recorded at CGUs in Italy, Algeria, Congo, the United States and Turkmenistan; (ii) the Refining & Marketing business (€1,225 million), mainly at refineries driven by a lowered outlook for refining margins and expectations for a continuing narrowing in spreads between medium-sour crudes vs light-sweet crude qualities; (iii) impairment losses of Chemical assets due to deteriorated margins scenario (€46 million).

Write-off charges amounted to €329 million and mainly related to previously capitalized costs of exploratory wells which were expensed through profit because it was determined that they did not encounter commercial quantities of hydrocarbons or due to lack of management commitment in pursuing further appraisal activity mainly in Libya, the United States, Angola, Egypt, Oman, Mexico and Lebanon.

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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,
	2020		2019		2018
	(€ million)
Exploration & Production		(610)		7,417		10,214
Global Gas & LNG Portfolio		(332)		431		387
Refining & Marketing and Chemicals		(2,463)		(682)		(501)
Eni gas e luce, Power & Renewables		660		74		340
Corporate and other activities		(563)		(688)		(668)
Impact of unrealized intragroup profit elimination		33		(120)		211
Operating profit (loss)		(3,275)		6,432		9,983

Exploration & Production. In 2020, the Exploration & Production segment reported an operating loss of €610 million, with a decrease of €8,027 million compared to the operating profit of €7,417 million reported in 2019. The decrease was driven by significantly lower oil and natural gas prices, lower production, higher impairment losses and higher write-offs of capitalized exploration expenses.

In 2020, the Company’s liquids and gas realizations decreased on average by 33.6% in dollar terms, driven by a weak trading environment. Eni’s average oil realizations decreased on average by 37.5%, in line with the decrease recorded in international oil prices for the Brent market benchmark (down by 35.2% for the year). Eni’s average gas realizations decreased by 23.9%. The decrease in gas realization prices did not take into account the lower prices realized when reselling volumes of non-equity gas of the Libyan partner. This resale price is excluded from the calculation of Eni’s average realized gas prices because Eni’s realized prices are calculated only with reference to equity production.

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 non-core gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. In 2020, non-core gains and losses included impairment charges of oil&gas assets (€1,888 million), an allowance for doubtful accounts (€77 million) and risk provisions (€114 million).

Excluding those items, the E&P segment reported a Non-GAAP operating profit of €1,547 million, with a decrease of €7,093 million from 2019, down by 82%, driven by: (i) a negative impact of the trading environment for an estimated €6.7 billion due to significantly lower oil and natural gas prices in all the geographies, particularly in the second quarter of the year which was the hardest hit by the downturn. Furthermore, the result was affected by a loss incurred in reselling Libyan non-equity gas volumes; (ii) lower production volumes due to lower capital expenditures, which negatively affected the development of reserves which were intended to preserve the Company’s cash flows in response to the COVID-19 crisis, the need to comply with the production quotas enacted by OPEC+ countries, lower gas offtakes at our fields in Egypt due to a demand downturn and reduced equity production volumes in Libya since during the year a contractual parameter already envisaged in the contract was triggered and will be applied going

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forward, as well as force majeure at certain fields until September 2020; (iii) higher write-off expenses relating to unsuccessful exploration wells (€314 million). These negative trends were partly offset by optimization of operating expenses and lower DD&A.

	Year ended December 31,
	2020		2019		2018
Exploration & Production	(€ million)
GAAP operating profit (loss)		(610)		7,417		10,214
Impairment losses (impairment reversals), net		1,888		1,217		726
Net gains on disposal of assets		1		(145)		(442)
Environmental provisions		19		32		110
Risk provisions		114		(18)		360
Reclassification of currency derivatives and translation effects to management measure of business performance		13		14		(6)
Valuation allowance of disputed receivables and others		77		123		158
Reinstatement of Eni Norge amortization charges						(375)
Other		45				105
Total gains and charges		2,157		1,223		636
Non-GAAP operating profit (loss)		1,547		8,640		10,850

Global Gas & LNG Portfolio (GGP). This segment is engaged in the supply and sale of wholesale natural gas by pipeline, international transport and purchase and marketing of LNG. It includes gas trading activities finalized to hedging and stabilizing sale margins, as well as optimizing the gas asset portfolio. In 2020, the GGP segment reported an operating loss of €332 million compared to a profit of €431 million of the previous year, due to commodity derivatives losses.

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 gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. The items excluded from GAAP operating profit (loss) in determining the Non-GAAP measure of profitability mainly include effects associated with commodity fair-valued derivatives.

Particularly, 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 are 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 receivable 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.

Excluding the below-listed gains and charges, the GGP segment reported a Non-GAAP operating profit of €326 million, with an increase of €133 million from 2019. This improvement was mainly driven by the optimization of the gas assets portfolio, leveraging high price volatility and contracts’ flexibilities (such as volumes flexibilities provided by long-term, take-or-pay supply contracts, access to transport and storage capacities), as well as to a favorable outcome of an LNG contract renegotiation closed in the third quarter

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of 2020. These positive trends more than offset the lower performance due to a contraction in gas demand at the main European markets due to the COVID-19 pandemic and lower LNG off-takes by our clients in Asia, mainly in the second quarter of 2020, that was the height of the crisis.

	Year ended December 31,
	2020		2019		2018
Global Gas & LNG Portfolio	(€ million)
GAAP operating profit (loss)		(332)		431		387
Impairment losses (impairment reversals), net		2		(5)		(73)
Provision for redundancy incentives		2		1		4
Fair value gains/losses on commodity derivatives		858		(576)		(63)
Reclassification of currency derivatives and translation effects to management measure of business performance		(183)		109		111
Other		(21)		233		(88)
Total gains and charges		658		(238)		(109)
Non-GAAP operating profit (loss)		326		193		278

Refining & Marketing and Chemicals. In 2020 the Refining & Marketing and Chemicals segment reported an operating loss of €2,463 million, compared to an operating loss of €682 million reported in 2019, a deterioration of €1,781 million, driven by a challenging trading environment, higher impairment losses, as well as a decrease in the book value of inventories accounted for under the weighted-average cost method of accounting.

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

In addition to the inventory holding loss, the non-core items of this segment for the year 2020 also comprised (i) significant impairment losses recorded at the Sannazzaro refinery and other plants, reflecting a lowered outlook for refining margins and expectations for a continuing narrowing in spreads between medium-sour crudes vs light-sweet crude qualities (€1,225 million); (ii) impairment losses of Chemical assets due to a lowered profitability outlook (€46 million); (iii) environmental provisions (€85 million); (iv) provision for redundancy incentives (€27 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 non-core 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, R&M business reported a Non-GAAP operating profit of €235 million (€289 million in 2019), while the Chemical business reported a Non-GAAP operating loss of €229 million (a loss of €268 million in 2019).

The refining activity was negatively affected by a sharply depressed scenario, which was driven by the pandemic-induced crisis in fuels demand and by narrowing differentials between sour/heavy crude oil qualities vs light crudes like the Brent benchmark which negatively affected the profitability of complex

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refinery cycles. Reduced refining margins also pressured the Company to cut the refinery runs, against the backdrop of overcapacity, competitive pressure and high levels of inventories. These impacts were partially offset by optimization actions of the industrial setup and by a positive performance of the bio-refineries thanks to higher processed volumes and margins. The marketing business reported steady results, despite lower sales volumes due to improved margins and lower expenses.

The Chemical business reported an adjusted operating loss of €229 million in 2020, with an improvement of 15% compared to 2019. This was achieved notwithstanding the strong reduction of sale volumes recorded in the second and the third quarter of 2020 due to an economic downturn in Europe triggered by the restrictive measures implemented during the COVID-19 pandemic’s peak, which reduced the consumption of plastics in core industries like the automotive sector. Furthermore, lower sales volumes were negatively affected by reduced product availability due to longer maintenance standstills at the production hubs in response to the COVID-19 emergency (particularly at the steam-cracker of Priolo and the Brindisi hub). Strengthening economic recovery in Asia in the final part of the year, softening competitive pressures and a margin recovery especially at the polyethylene business supported the business recovery in the last part of the year, which also benefitted of higher product availability.

	Year ended December 31,
	2020		2019		2018
Refining & Marketing and Chemicals	(€ million)
GAAP operating profit (loss)		(2,463)		(682)		(501)
(Profit) loss on inventory		1,290		(318)		234
Environmental provisions ond other costs		85		244		193
Impairment losses (impairment reversals), net		1,271		922		193
Net gains on disposal of assets		(8)		(5)		(9)
Risk provisions		5		(2)		21
Provision for redundancy incentives		27		8		8
Fair value gains/losses on commodity derivatives		(185)		(118)		120
Reclassification of currency derivatives and translation effects to management measure of business performance		10		(5)		5
Other		(26)		(23)		96
Total gains and charges		2,469		703		861
Non-GAAP operating profit (loss)		6		21		360
– Refining & Marketing		235		289		370
– Chemicals		(229)		(268)		(10)

Eni gas e luce, Power & Renewables. This segment engages in retail sales of gas, electricity and related services, production and wholesale sales of electricity from thermoelectric and renewable plants. It includes trading activities of CO2 emission certificates and forward sale of electricity with a view to hedging/optimising the margins of the electricity.

In 2020, this segment reported an operating profit of €660 million, an increase of €586 million compared to the profit of €74 million of the previous year, mainly due to a better performance of the retail business.

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 gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. The items excluded from GAAP operating profit in determining the Non-GAAP measure of profitability mainly include effects associated with commodity fair-valued derivatives.

Particularly, we enter into commodity derivatives to reduce our exposure to the commodity risk due to different indexation between the purchase cost and the selling price of gas and power or to lock in a commercial margin once a sale contract has been signed or is highly probable. These derivatives normally hedge the Group net exposure, but do not meet the requirements for being accounted for as hedges in accordance to IFRS.

Therefore, in explaining year-on-year charges 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, including the ineffective portion of cash flow hedges.

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Excluding the below-listed gains and charges, the Eni gas e luce, Power & Renewables segment reported a Non-GAAP operating profit of €465 million, with an increase of €95 million from 2019, or 25.7%.

The retail gas and power business, managed by Eni gas e luce, reported a Non-GAAP operating profit of €325 million in the full year up by €47 million notwithstanding reduced sales due to lower consumption following the economic downturn and higher provisions for impairment losses of trade receivables. Performance was supported by commercial and efficiency initiatives which drove reduced operating expenses, higher revenues from extra-commodity business in Italy and by an expansion of the customers portfolio in France and Greece.

The Power and Renewables business reported a Non-GAAP operating profit of €140 million (€92 million in 2019) driven by higher product margins.

	Year ended December 31,
	2020		2019		2018
Eni gas e luce, Power & Renewables	(€ million)
GAAP operating profit (loss)		660		74		340
Risk provisions		10
Impairment losses (impairment reversals), net		1		42		2
Environmental provisions		1				(1)
Provision for redundancy incentives		20		3		118
Fair value gains/losses on commodity derivatives		(233)		255		(190)
Reclassification of currency derivatives and translation effects to management measure of business performance				(10)		(3)
Other		6		6		(4)
Total gains and charges		(195)		296		(78)
Non-GAAP operating profit (loss)		465		370		262
of which:
– Eni gas e luce		325		278		201
– Power & Renewables		140		92		61

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.

The aggregate Corporate and Other activities reported an operating loss of €563 million in 2020, a reduction of €125 million from 2019, or 18.2% benefitting from optimization and efficiency initiatives.

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e) Net finance expenses

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

	Year ended December 31,
	2020		2019		2018
	(€ million)
Income (expense) on derivative financial instruments		351		(14)		(307)
of which – Derivatives on exchange rate		391		9		(329)
– Derivatives on interest rate		(40)		(23)		22
Exchange differences, net		(460)		250		341
Finance expense from banks on short and long-term debt		(619)		(740)		(685)
Interest expense for lease liabilities		(347)		(378)
Interest income due to banks		10		21		18
Net income from financial activities held for trading		31		127		32
Finance expense due to the passage of time (accretion discount)		(190)		(255)		(249)
Other finance income and expense, net		106		17		(173)
		(1,118)		(972)		(1,023)
Finance expense capitalized		73		93		52
NET FINANCE EXPENSES		(1,045)		(879)		(971)

In 2020, net finance expenses were €1,045 million, €166 million higher than in 2019. This increase was due to a lower balance between gains/losses due to currency translation differences at dollar-denominated payables and receivables accrued by Italian subsidiaries, and the change in the fair value of exchange derivatives as the Group normally pools different exposures to the currency risk retained by operating subsidiaries and then hedges the Group net exposure to the risk, which lack the formal criteria to be designated as hedges under IFRS and therefore are recognized through profit and loss.

2020 net finance expenses include lower finance expense relating to the accretion discount of liabilities (up by €65 million) recognized at present value due lower discount rates.

Interest expense on short and long-term debt due to banks and other financing institutions decreased by about €120 million due to lower benchmark interest rates.

Net income from assets held-for-trading decreased by about €100 million due to lower yields and a reduction in fair value driven by the depreciation of the US dollar and the economic downturn.

f) Net income from investments

In 2020 the Group reported a net loss from investments of €1,658 million mainly related to Eni’s share of losses incurred by equity-accounted investments (€1,733 million) driven by losses in the E&P (€980 million), R&M and Chemicals (€363 million) and Corporate and other activities (€381 million) segments, respectively in:

(i)

the E&P joint venture Vår Energi, where we recognized a loss of €918 million mainly driven by lower hydrocarbons prices and impairment losses recorded at oil&gas assets due to a revised oil price outlook and downward reserve revisions.

(ii)

ADNOC Refining associate, where we recognized a loss of €291 million, relating to the alignment of raw material and products inventories to their net realizable values at period end and lower refining margins.

(iii)

The Saipem joint venture, where we recognized a loss of €354 million driven by an unfavorable trading environment on the back of capex cuts implemented by oil&gas companies which reduced the joint ventures revenues and profitability as well as impairment losses and other restructuring charges.

These losses were partly offset by dividends of €150 million paid by minority investments in certain entities which were designated at fair value through other comprehensive income under IFRS 9 except for dividends which are recorded through profit. These entities mainly comprised Nigeria LNG Ltd (€113 million, where Eni has an interest of 10.4%) and Saudi European Petrochemical Co (€28 million, where Eni has an interest of 10%).

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	Year ended December 31,
	2020		2019		2018
	(€ million)
Share of gains (losses) from equity-accounted investments		(1,733)		(88)		(68)
Dividends		150		247		231
Net gains (losses) on disposals				19		22
Other income (expense), net		(75)		15		910
		(1,658)		193		1,095

g) Taxes

In 2020, income taxes amounted to €2,650 million, notwithstanding the Group incurring a loss before income taxes of €5,978 million. This was driven by a depressed pricing scenario which reduced the Group profitability outlook driving the write-off of previously recognized deferred tax assets (of about €1.3 billion) due to the projections of lower future taxable profit and limiting the ability of the Company to recognize new deferred tax assets on losses for the year. Due to these drivers, the reported tax rate was not significant.

Excluding the identified losses disclosed above, particularly the impairments of tangible assets and the write-off of previously recorded deferred tax assets, the Group tax rate would be significantly high at more than 100% and well above the 2019 tax rate because of the impact a depressed scenario, which determined a higher relative weight of certain transactions and therefore higher distortive effects of certain tax items than in the past. Particularly, the Group tax rate was significantly and negatively affected by the following trends:

—

the incurrence of non-deductible expenses and losses, because their tax recognition depends on the achievement of certain project milestones (such as a project FID) as in the case of explorations expenses or due to being related to intercompany losses as in the case of the one incurred in connection with the resale of the non-equity Libyan gas entitlements;

—

the inability to recognize tax-losses carryforwards in certain jurisdictions due to lack of sufficient future taxable profits against which deferred tax assets are offset as required by IAS 12;

—

the recognition of current income taxes on intercompany dividend distribution which created a mismatch due to absence of pre-tax profit at Group level (intercompany dividends are eliminated in the consolidation process).

Net of these factors, management estimated the Group’s tax rate at about 70% reflecting the high impact in the Eni’s portfolio of PSA oil contracts, which bear tax rates less sensitive to oil prices.

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, borrowings and divestments of minority interests in certain of our exploration assets and other non-strategic activities. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and balanced financing structure.

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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,
	2020		2019		2018
	(€ million)
Net profit (loss)		(8,628)		155		4,137
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		12,641		10,480		7,657
– net gains on disposal of assets		(9)		(170)		(474)
– dividends, interest, taxes and other changes		3,251		6,224		6,168
Changes in working capital related to operations		(18)		366		1,632
Dividends received by equity investments		509		1,346		275
Taxes paid		(2,049)		(5,068)		(5,226)
Interests (paid) received		(875)		(941)		(522)
Net cash provided by operating activities		4,822		12,392		13,647
Capital expenditures		(4,644)		(8,376)		(9,119)
Acquisition of investments and businesses		(392)		(3,008)		(244)
Disposals of consolidated subsidiaries, businesses, tangible and intagible assets and investments		28		504		1,242
Other cash flow related to investing activities		(735)		(254)		942
Net cash inflow (outflow) related to financial activities(*)		1,156		(279)		(357)
Changes in short and long-term finance debt		3,115		(1,540)		320
Repayment of lease liabilities		(869)		(877)
Dividends paid and changes in non-controlling interests and reserves		(1,968)		(3,424)		(2,957)
Net issue (repayment) of perpetual hybrid bond		2,975
Effect of changes in consolidation and exchange differences of cash and cash equivalent		(69)		1		18
Net increase (decrease) in cash and cash equivalent		3,419		(4,861)		3,492
Cash and cash equivalent at the beginning of the year		5,994		10,855		7,363
Cash and cash equivalent at year end		9,413		5,994		10,855

(*)

From 2019, Eni’s cash flow statement is reporting in a dedicated line-item the net cash outflow (investments minus divestments) in held-for-trading financial assets and current non-operating receivables financing, with the latter being investment of temporary cash surpluses. Those two assets are netted against financial liabilities to determine the Group net borrowings . In previous reporting periods, cash inflows and outflows relating those assets were reported among investing activities or divesting activities relating to securities and financing receivables, respectively. The establishment of a dedicated line-item for these cash flows enables the users of financial statements to promptly reconcile the statutory cash flow statement to the Non-Gaap financial disclosure relating to changes in the Company’s net borrowings, because the difference between the two cash flow statements is the net investment in held-for-trading securities and current non-operating receivables financing which are part of net cash from financing activities in the Non-Gaap cash flow statements. The cash flow statements of comparative periods have been reclassified accordingly.

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	Year ended December 31,
	2020		2019		2018
	(€ million)
Net cash provided by operating activities		4,822		12,392		13,647
Capital expenditures		(4,644)		(8,376)		(9,119)
Acquisitions of investments and businesses		(392)		(3,008)		(244)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments		28		504		1,242
Other cash flow related to capital expenditures, investments and divestments		(735)		(254)		942
Repayment of lease liabilities		(869)		(877)
Net borrowings(1) of acquired companies		(67)				(18)
Net borrowings(1) of divested companies				13		(499)
Exchange differences on net borrowings and other changes		759		(158)		(367)
Dividends paid, share repurchases and changes in minority interest and reserves		(1,968)		(3,424)		(2,957)
Net issue (repayment) of perpetual hybrid bond		2,975
Change in net borrowings(1) before IFRS 16 effects		(91)		(3,188)		2,627
IFRS 16 first application effect				(5,759)
Repayment of lease liabilities		869		877
Inception of new leases and other changes		(239)		(766)
Change in net borrowings after IFRS 16 effects(1)		539		(8,836)		2,627
Net borrowings(1) at the beginning of the year		17,125		8,289		10,916
Net borrowings(1) at year end		16,586		17,125		8,289

(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 2020, adjustments to reconcile the net loss incurred in the year to net cash provided by operating activities mainly related to non-monetary charges, which primarily regarded depreciation, depletion, amortization and impairment charges and the write-off of tangible and intangible assets (€10,816 million). Adjustments to net profit also included accrued income taxes (€2,650 million) and interest expense (€877 million), which were partly offset by amounts actually paid (€2,049 million and €875 million, respectively).

Net profit was negatively impacted by extraordinary credit losses related to a valuation allowance for doubtful accounts incurred in the E&P business and certain provisions for an overall amount of €128 million.

a) Changes in working capital related to operations

In 2020, working capital generated an outflow of €18 million. This was mainly due to the outflows in connection with a negative balance between trade receivables collected and trade payables paid (€298 million) mainly in the E&P segment, the utilization of trade advances cashed by Egyptian partners in previous reporting periods in relation to the financing of the Zohr project (an outflow of €254 million) as well as the settlement of certain contractual disputes in the E&P business (an outflow of about €500 million) which were provisioned in the previous reporting periods. These outflows were offset by an inflow related to a reduction in the book value of inventories due to the alignment to their net realizable values at period-end (an inflow of €1,054 million) which were negatively affected by lower oil and product prices. This inflow pared a corresponding amount recognized in the profit and loss account because the change in the book values of inventories is credited to profit and loss.

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	Year ended December 31,
	2020		2019		2018
	(€ million)
Exploration & Production		3,472		6,996		7,901
Global Gas & LNG Portfolio		11		15		26
Refining & Marketing and Chemicals		771		933		877
Eni gas e luce, Power & Renewables		293		357		238
Corporate and other activities		107		89		93
Impact of unrealized intragroup profit elimination		(10)		(14)		(16)
Capital expenditures		4,644		8,376		9,119
Acquisitions of investments and businesses		392		3,008		244
		5,036		11,384		9,363
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments		(28)		(504)		(1,242)

Capital expenditures totaled €4,644 million and €8,376 million, respectively in 2020 and in 2019.

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

Acquisition of investments and businesses totaled €392 million in 2020 and mainly related to the acquisition of the control of the Evolvere company (approximately €100 million) which engages in the business of distributed generation from renewable sources, and of minority interests in Finproject (approximately €70 million), which engages in the manufacturing of specialized polymers, and in Novis Renewables Holdings (approximately €60 million), which engages in building and commissioning renewable power facilities in the USA, as well as capital contributions made to certain equity-accounted entities engaged in the execution of projects of Eni’s interest.

In 2020, disposals amounted to €28 million and related to minor non-strategic assets mainly in E&P (€14 million) and R&M (€11 million) businesses.

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

In 2020, dividends paid and changes in non-controlling interests and reserves (€1,968 million) related to the dividends paid to Eni shareholders (€1,965 million which comprised the 2019 final dividend for about €1,535 million and the 2020 interim dividend corresponding to one-third of the floor dividend amounting to about €430 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 (financing receivables and securities). The Company is retaining a liquidity reserve, which comprises very liquid investments, mainly sovereign bonds and corporate securities which management has selected based on their creditworthiness. This cash reserve was established by investing part of the proceeds from the disposal plan carried out in the latest years. Those securities amounted to €5,502 million as of end of 2020 and were accounted as mark-to-market financial instruments. Of this amount, securities issued by industrial companies and financial institutions were €4.3 billion. For further information, see “Item 18 – Note 6 – Financial assets held for trading – of the Notes on Consolidated Financial Statements”. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow.

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 standards 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

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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,
	2020						2019
	Short-term		Long-term		Total		Short-term		Long-term		Total
Finance debt (short-term and long-term debt)		4,791		21,895		26,686		5,608		18,910		24,518
Lease liabilities		849		4,169		5,018		889		4,759		5,648
Cash and cash equivalents		(9,413)				(9,413)		(5,994)				(5,994)
Financial assets held for trading		(5,502)				(5,502)		(6,760)				(6,760)
Non operating financing receivables		(203)				(203)		(287)				(287)
Net borrowings including lease liabilities		(9,478)		26,064		16,586		(6,544)		23,669		17,125

	As of December 31,
	2020		2019
	(€million)
Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS		37,493		47,900
Ratio of finance debt including lease liabilities to total shareholders’ equity including non-controlling interest		0.84		0.63
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest		(0.40)		(0.27)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage)		0.44		0.36

At December 31, 2020, total finance debt of €26,686 million consisted of €4,791 million of short-term debt (including the portion of long-term debt due within twelve months equal to €1,909 million) and €21,895 million of long-term debt. At the same date, lease liabilities were €5,018 million (short-term portion €849 million).

Total finance debt included unsecured bonds for €19,420 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €1,644 million (including accrued interest and discount). Bonds issued in 2020 amounted to €3,514 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (75%), U.S. dollar (24%) and 1% in other currencies.

In 2020, net borrowings including lease liabilities amounted to €16,586 million, representing a €539 million decrease from 2019. This decrease was driven by the reduction of the IFRS 16 lease liabilities, which amounted to €5,018 million in 2020 compared to €5,648 million in 2019, down by €630 million. The IFRS 16 lease liabilities included €1,652 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 €11,568 million, substantially unchanged compared to December 31, 2019. Cash flow from operating activities of €4.82 billion and the issuance of two hybrid bonds for €2.97 billion, classified as equity for IFRS accounting purposes, provided sufficient funds to finance the capital expenditure incurred in connection with the program of exploring for and developing hydrocarbons reserves and other capital projects (€4.64 billion), acquisition expenditures for €0.39 billion and other cash-outs related to investing activities for €0.74 billion, to pay cash dividends to shareholders of approximately €1.97 billion and the repayment of the lease liabilities for €0.87 billion. Exchange rate differences of net borrowings were positive for €0.76 billion.

The ratio of finance debt to total equity was 0.84 at 2020 year-end, including the IFRS 16 lease liability (0.63 at 2019 year-end). Total equity decreased by €10,407 million from December 31, 2019. This was due to the net loss for the year (€8,628 million) and the payment of dividends to Eni’s shareholders

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(€1,965 million) as well as negative foreign currency translation differences (€3,314 million) reflecting the depreciation of the dollar vs. the euro as of December 31, 2020 vs. December 31, 2019, while the issuance of two hybrid bonds for approximately €3 billion and a positive change in the cash flow hedge reserve (€661 million) increased net equity.

The Group Non-GAAP measure of its financial condition mostly tracked by management was “leverage”, excluding the impact of IFRS 16, amounting to 0.31 at year end (0.24 at year-end 2019).

Capital expenditures by segment

Exploration & Production. In 2020, capital expenditures of the Exploration & Production segment amounted to €3,472 million, mainly related to the development of oil&gas reserves (€3,077 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, Indonesia, the United Arab Emirates, the United States, Angola, Mexico, Iraq and Kazakhstan. Exploration expenditures (€283 million) were directed in particular to Egypt, Vietnam, Libya, Mexico, Oman and Myanmar.

In 2020, a total amount of €57 million related to the purchase of proved and unproved reserves in Algeria.

Global Gas & LNG Portfolio. In 2020, capital expenditure in the Global Gas & LNG portfolio totaled €11 million and related to the international transport activities.

Refining & Marketing and Chemicals. In 2020, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €771 million and regarded mainly: (i) refining activity in Italy and outside Italy (€462 million) for the maintaining plants’ integrity and stay-in-business, as well as HSE initiatives; (ii) marketing activity (€126 million) for regulation compliance and stay-in-business initiatives in the retail network in Italy and in the rest of Europe; and (iii) plant upgrading, efficiency and compliance to stricter environmental and safety standards in the Chemical business (€183 million).

EGL, Power & Renewables. In 2020, capital expenditures in the EGL, Power & Renewables segment amounted to €293 million and mainly related to: (i) gas and power marketing in the retail business (€175 million); (ii) the increasing renewable installed capacity (€66 million); and (iii) the business of power generation (€52 million).

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,
	2020		2021
Average price of Brent dated crude oil in U.S. dollars(1)		51		61
Average EUR/USD exchange rate(2)		1.100		1.200
Standard Eni Refining Margin (SERM)(3)		3.6		(0.6)
Gas at the PSV in $/mmBTU		3.7		6.8

(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, 2021 the Brent crude oil price was approximately 61 $/BBL on average, approximately 20% higher than in the first quarter of 2020. This trend will positively affect reported revenues, profitability, and cash flow of our Exploration & Production segment in 2021. See “management expectations of operations” below. This positive trend will be partly offset by significantly lower refining margins and the appreciation of the EUR vs the US dollar.

The main business transactions occurred in the firth quarter 2021 are reported in Item 4.

Management’s expectations of operations

Business trends

Exploration & Production

In the next four-year plan 2021-2024, management will seek to boost the cash generation in the E&P segment leveraging on profitable production growth, capital discipline, effective project execution and strict control of operating expenses and working capital.

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Our production plans and financial projections are based on our Brent price scenario of 50 $/BBL in 2021 and on a gradual recovery in the subsequent years up to our long-term case of 60 $/BBL in 2023 and going forwards (on constant monetary term 2023, i.e. from 2024 onwards crude oil prices are assumed to grow in line with a projected inflationary rate). Our pricing assumptions are based on expectations of a global recovery in oil demand as more economies reopen and the pandemic crisis is successfully addressed in the United States and Western Europe, strengthening economic activity in Asia, a slow easing of production quotas by the producing countries of the OPEC+ agreement and strict capital discipline on part of international oil companies. There are some risks to this outlook, including uncertainties over the effective containment of the virus, a weaker-than-expected economic rebound in the United States and in Europe, uncertainties over consumers’ attitude to resume travelling, the possibility that the OPEC+ members could accelerate the abandonment of production curtailments and the return on the market of the Iranian production.

Due to those risks and uncertainties, management intends to retain a strong focus on capital and cost discipline, on shortening the projects cycle and on reducing the time-to-market of our reserves as levers to maintain our development projects profitable in a low-price scenario. We plan to invest €4.5 billion on average in the next four-year period to explore for and develop hydrocarbons reserves. Our capital projects will be carefully selected against our pricing assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure and the execution risk leveraging on a phased approach in developing our projects. 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. We plan to mitigate those risks in the future by continuing deployment of our skills and by our model of project execution driven by: (i) the execution in parallel of the main project activities, including discovery appraisal and pre-fid activities; (ii) the in-sourcing of critical engineering and project management phases, for example we are exercising strict control over construction, hook-up and commissioning; (iii) the 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; (iv) continuing progress in our technologies designed to improve drilling performance and the recovery factor; and (v) the promotion of the digital transformation of the business to further improve workplace safety and asset integrity.

Phased project development and strict integration between exploration and development have improved the 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. Due to those drivers and our estimation that in recent years our discovery costs have been efficient, we believe that the price breakeven of our ongoing projects has decreased over the latest years, thus reducing the risk of a volatile scenario.

Exploration will continue ensuring cost-effective replacement of produced reserves and supporting cash generation. Our exploration initiatives will be balanced between the following two clusters:

•

Exploration projects in proven/mature areas and near-field i.e. in prospects 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. This approach has paid off in recent years; for example in 2020 we made four near-field discoveries in Egypt which have been already put into production due to proximity to infrastructures;

•

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

Our dual exploration model contemplates the acquisition of high interests in exploration leases and, in case of exploration success, the partial divestiture of the discovered resources with a view of accelerating the conversion of resources into cash or of accomplishing asset swaps.

Within the capital plans adopted, we are targeting a 4% average growth rate in hydrocarbons production up to a plateau of approximately 2 million boe/d in the 2021-2024 plan period. In 2021, we expect production to be flat year-over-year, assuming OPEC cuts of aroung 40 kboe/d.

Growth in the 2022-2023 period is expected to be fueled organically by new fields start-ups and the achievement of full-field production at our main producing fields, including the Zohr gas field in Egypt,

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Block 15/06 in Angola and the Area 1 fields off Mexico, as well as continuing production optimization to counteract fields natural decline. The main start-ups expected in the plan period include a few projects operated by our JV Var Energi in Norway (including J. Castberg and Balder X), the Merakes project in Indonesia, the gas discovery of Coral in Area 4 offshore Mozambique, the Dalma and Sharjah gas fields in the UAE and other developments. We estimate that new field start-ups, production ramp-ups and expansion projects of existing fields will add approximately 665 KBOE/d of new production by 2024. We have good visibility as to the ability to achieve those production targets because they relate to already-sanctioned projects, most of which are operated, and to incremental development phases at our existing profit centers. Major production increases are expected in Egypt, UAE, Norway, Angola, Kazakhstan and Mozambique, while production in Libya is forecast to decline since during 2020 a contractual parameter already envisaged in the contract has been triggered and it will applied going forward.

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. In 2020, certain of our fields in Libya were shut down until September due to a situation of social and political instability of the Country which led to the blockade of export ports in the eastern part. However, the above-mentioned 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. Based on this, we forecast to lessen going forward our dependence on less politically stable areas such as Libya, where we expect to reduce the weight of this country production relative to our portfolio, by increasing the size of more stable areas like UAE, Mexico, Norway and Mozambique.

Global Gas & LNG Portfolio

We expect continuing volatility in the spreads between gas spot prices at hubs in the northern Europe, which are the main indexation parameter of our supply contracts, and prices at the spot market in Italy, which is the main market to sell our procured gas. In the LNG business, we expect a muted margin environment.

Against this scenario, the Company 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 contracts to align pricing terms 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 market volatility;

(iii)

To grow the LNG marketing business leveraging on the integration with the E&P segment with the aim of maximizing the profitability along the entire gas value-chain. We plan to increase contracted supplies of LNG to achieve a robust portfolio of reselling opportunities, and we are targeting 14 million tons/year of contracted volumes of LNG by 2024, of which 70% deriving from our equity production.

We make use of commodity and financial derivatives to hedge us 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 to IFRS and consequently are recorded through profit and loss and may add a component of volatility to our results of operations. Furthermore, we make use of derivatives to improve margins by leveraging on market volatility and availability of assets to capture arbitrage opportunities (for example the winter vs summer spread, the Italian spot market vs the continental spot markets spread, the spot vs. the Brent indexation spread). Those derivatives are of speculative nature with gains and losses recognized through profit. Our 2020 results were helped by this asset-backed trading leveraging the high market volatility recorded in the year; however, it is difficult to make accurate forecast about future trends in this activity.

Our profitability outlook factors in the expected outcome of ongoing and planned renegotiations of the Company long-term supply contracts which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3.

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Refining & Marketing

The outlook of the European refining sector is challenging due to the material reduction of demands for gasoline, kerosene, gasoil and other fuels caused by the consequences of the pandemic on travel and the slow pace of recovery in consumption, because many economies in Europe are still in lockdown. The competitive landscape is also weak due to overcapacity, high global products inventories, increasing adoption of electric vehicles and margin pressure from cheaper products streams from the Middle East and other areas, where large expansion projects in new refineries or in the upgrading of existing plants are anticipated.

Management expects refining margins to remain subdued in the next four years and beyond. Furthermore, our refineries are exposed to narrowing price differentials between sour crudes vs. the Brent benchmark, which negatively affects the profitability of our complex refineries eroding the cost advantage in processing sour crudes, which generally trade at a discount vs the Brent crude quality.

Against this backdrop, the Company priority is to restore the profitability of its oil-based refineries in a depressed downstream oil environment by means of capital discipline, asset optimizations to increase plant reliability, maximizing yields of valuable fuels and improving efficiency in energy consumption and operating costs.

We intend to maximize the returns at our investment in ADNOC Refining, where we acquired a 20%-stake in 2019. We are planning to deploy our technological lead and plant expertise with the objective of improving the refinery efficiency and profitability. We are sponsoring capital projects designated to upgrade the refinery capacity to process alternative crudes with high sulfur content, (non-system ones too) to increase plant efficiency and to valorize refinery by-products. These projects will be funded by the refinery cash flows. Also, a trading joint venture has been established and started operations to capture a larger share of the value associated with the refinery products.

In recent years we have implemented a plan to reduce the share of traditional, cost-dis-advantaged refineries in our portfolio by upgrading the Venice and Gela plants to bio-refineries based on proprietary technologies. In 2020 we achieved the full ramp-up of the Gela plant, bringing installed capacity at our bio-refineries to 1.1 million tons per year, with profitable crack spreads between the cost of the bio feedstock and the biofuels. We plan to double the manufacturing capacity of bio-fuels to 2 million tons per year by the end of 2024. We are planning to progressively phase-out palm oil as a feedstock and replace it with more environmentally sustainable feedstock; the feedstock will be palm oil free in 2023.

In Marketing activities, where we expect a very competitive environment due to lack of entry barrier and of product differentiation, we are planning 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 in the marketing and distribution activities. Further value will be extracted by the development of our initiatives in the segment of sustainable mobility and new fuels (for example the service of recharging electric vehicles, the supply compressed natural gas and of LNG, as well as the start of the supply of hydrogene) and selling non-fuel products and services.

Chemicals business

The outlook in the chemicals business is challenging due to the prospects of a slow post-pandemic recovery in the Eurozone and rising oil-based feedstock costs, which could possibly squeeze product margins. Furthermore, the commodity plastics business is a very competitive market and the profitability of our chemicals business is expected to be negatively affected by rising competitive pressures from cheaper products stream from producers in Middle East and in the United States which can leverage on larger plant scale and lower feedstock costs (as in the case of ethane-feed crackers). Looking forward we believe that a business upgrade is needed to achieve profitable and cash-positive operations. The long-term strategy of our chemicals business is to diversify the products portfolio by reducing the weight of commodities, which are less profitable and are exposed to the volatility of the oil cycle, and to expand our presence in the segments of the green chemistry, circular economy projects and specialized polymers where we can leverage on competitive advantages like proprietary technologies. Other planned optimizations measures include: (i) strengthening the productive footprint of traditional product lines by means of improved plant integration and reliability as well as by rightsizing our captive ethylene capacity vs internal needs for the production of polyethylene; (ii) upgrading the product mix by developing differentiated products, leveraging on new applications through internal R&D; (iii) developing the international presence of our chemical business leveraging on proprietary technologies targeting markets with growth opportunities and access to competitive feedstock and outlets.

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Eni gas e Luce, Power & Renewables

We expect steady profitability in the business of marketing gas and power to the retail customers in Italy and other European markets. Going forward, profitability in this business will be underpinned by selectively growing our customer base, which is expected to reach more than 11 million customers by 2024, 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. To maximize the synergies between the retail business and the renewable power business we intend to merge the two businesses. We plan to accelerate the development of the installed capacity to produce renewable power to reach 4 GW by 2024 by finalizing the several growth opportunities in portfolio.

Expected Group financial performance

In the first quarter of 2021, crude oil prices staged a significant recovery with the Brent crude benchmark averaging more than 60 $/bbl, up from the average of 44 $/bbl recorded in the fourth quarter of 2020 and the average at 42 $/bbl for the FY 2020. This trend was driven by an improving oil market outlook due to signs of demands rebound, a disciplined approach among OPEC+ members in relation to curbing production quotas and about compliance levels, tight capital plans on part of international oil companies and a strengthening macroeconomic recovery, particularly in China and other Asian countries. However, considering the risks and uncertainties to this outlook in connection with a possible recrudescence of the COVID-19 pandemic, persistently high levels of global inventories of oil and products as well as weak consumers’ confidence in the United States and in Western Europe, management is retaining a disciplined and selective approach in capital spending within a financial framework which prioritizes the maintenance of a robust balance sheet and strong indebtedness and liquidity ratios, and the achievement of progressive and competitive shareholders’ returns. Furthermore, the first quarter of 2021 saw a significant deterioration in refining margins because the cost of the oil-based feedstock has increased, while refined products prices have weakened due to a continued contraction in demand for fuels in our reference markets (Italy and Western Europe). Finally, the appreciation of the EUR vs the US dollar in the quarter will negatively affect the reported revenues and cash flows of our Exploration&Production segment.

Our financial strategy aims to reduce the level of Brent price needed to fund with our cash flow from operations all of our organic capital expenditures (i.e. expenditures that exclude acquisitions) and the floor dividend.

In 2021, we plan to invest less than €6 billion in the business and to invest on average less than €7 billion per year in the 2021-2024 financial plan for an overall capital budget of about €27 billion, which is significantly lower than our historical levels of capital budgets. We plan to invest €4.5 billion on average in the next four year in the E&P business to maintain production, develop our pipeline of projects and to fund exploration activities to ensure the replacement of reserves. The businesses of the energy transition will attract €9 billion in the next four years, which will be used to increase the generation capacity of power from renewable sources, to upgrade the manufacturing capacity at our bio-refineries, to develop projects of circular economy and to expand our market share in the retail market of gas and power. This capital plans retains some degree of flexibility because about 55% of our capex in the E&P business expected in 2023-2024 remains uncommitted.

As part of our financial framework, we have designed a new, flexible dividend policy which features a floor dividend plus a variable amount correlated to ongoing trends in the oil environment. The floor dividend is currently set at €0.36 per share conditional upon an average Brent price for the reference year of at least 43 $/bbl and will be upgraded going forward based on the Company’s delivering on its strategy and industrial targets. In addition to the floor dividend, a variable dividend will be paid to shareholders as a portion of the incremental cash flow from operations in excess over capital expenditures, which we expect to earn due to oil prices rising above the threshold of 43 $/bbl. The ratio of such pay-out would grow reflecting any growth in oil price, from 30% up to 45% of the incremental cash flow generated at Brent prices above 43 $/bbl and up to 65 $/bbl. The dividend is expected to be paid in two instalments of equal amounts in May and September of each year.

In 2020 in response to the downturn we suspended our planned share buy-back. Considering the improving outlook, we expect to resume the buy-back in the event of a Brent price of 56 $/bbl, compared to the triggering level of the prior policy which was above 60 $/bbl. At a Brent price of 56 $/bbl we expect to make a buy-back of €300 million. Buyback will rise to €400 million per year at a Brent scenario of 61 $/bbl and to €800 million per year from 66 $/bbl as per prior policy.

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Our goal is to achieve in 2024 cash neutrality at a Brent price of less than 40 $/bbl to fund the Group’s organic capital expenditures (i.e. capital expenditures excluding acquisitions) and the floor dividend, leveraging the expected improvement in our profitability due to the industrial actions that we are planning to execute under our Brent scenario of 50 $/bbl in 2021 rising up to 60 $/bbl in 2023:

(i) to grow profitably our hydrocarbons production at an average rate of 4% in the 2021-2024 plan period. In 2021, a transition year before fully recovering from COVID-19, production guidance is flat year-over-year, assuming OPEC+ cuts of around 40 kboe/d in the year. During the four-year plan, fourteen major projects will be brought on stream, operating over 70% of the new production. These are mainly in Angola, Indonesia, Mexico, Mozambique, Norway and United Arab Emirates. In terms of future production mix, around 55% of proven reserves will be made up of gas at the end of 2024.

We plan to maximize the E&P segment cash generation by increasing production while maintaining flat capital spending over the next four years. This will be driven by production ramp-up at projects with already installed production capacity (like in Egypt), focused exploration activities in proven and mature area given our track record of finding new resources near-fields in production and a focus on short-life projects.

(ii) to hold steady profitability at our Global Gas & LNG Portfolio business by leveraging the extraction of value from our assets in Europe (long-term contracts, access to pipelines and storage capacity) supported by our trading capabilities and by growing our LNG sales targeting premium markets in Middle East and Far East. We plan to have a portfolio of about 14 million tons/year of contracted LNG in 2024 by exploiting the integration with the E&P business which will account for more than 70% of the supply portfolio and the ramp-up of the Damietta plant in Egypt;

(iii) to improve the profitability of the R&M business which will be driven by optimizing the asset base at our oil-based refineries to drive better plant performance and cost savings, by increasing the production volumes of bio-fuels which are earning good margins and by maximizing the value of our investment in ADNOC Refining. Our network of fuels stations delivered a resilient performance during the downturn and we expect it to continue performing steadily in the next four years thanks to efficiency actions and investments to upgrade our service stations to retain the market share and to evolve them to support an expected increase in smart mobility services;

(iv) the chemicals business managed by our subsidiary Versalis will need to complete its restructuring to reduce the weight in the portfolio of the business lines exposed to the volatility of the oil scenario by a corresponding increase in the sectors of the green chemistry, specialized polymers and circular economy where we believe to have more market power and competitive advantages. Rightsizing of capacity in the basic petrochemicals business, plant optimizations, cost savings and capital discipline will contribute to restore the profitability of our operations; and

(v) the business of marketing gas and power to the retail sector in Italy and some European countries, managed by our subsidiary Eni gas e luce, is expected to increase its profitability leveraging a planned increase in the number of clients and an increasing weight in the product mix of green power thanks to the synergies with the business of renewable generation. The two businesses are set to be combined in a single entity. Other areas of margin improvement will be the effectiveness of marketing operations, a constant focus on credit collection and on minimizing credit losses, the expansion of revenues in the supply of extra-commodity product and services and cost efficiencies.

Considering the risks and uncertainties in the oil scenario, as of the end of 2020 we retained a cash reserve large enough to cover the expected financial obligations coming due in the next twelve months. Furthermore, we have identified a cluster of non-strategic assets that we intend to dispose of with expected gross proceeds of more than €2 billion, also contributing to rationalizing the E&P asset portfolio and optimizing the asset base in other businesses. We may use those proceeds to fund targeted acquisitions in line with our objective of portfolio reshaping.

The action planned in the next four-year period and our cash reserves will underpin a robust balance sheet with our core ratio of net borrowings to total equity – leverage – before the effects of IFRS 16 expected in the range of 30% in 2021 and declining thereafter.

This financial outlook is subject to the volatility of crude oil prices. Based on our current portfolio of oil&gas asset we estimate that, holding all other factors constant, our cash flow from operations vary by approximately €0.15 billion for each dollar change in the Brent price and proportional variations in natural gas prices on a yearly basis compared to our price forecast of 50 $/BBL for 2021. Currently, oil prices are in an uptrend due to the recent developments occurred until now in 2021 described above, with the average

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Brent price for the first quarter of 2021 at above 60 $/bbl. This trend will be partly offset by the significant contraction recorded by the refining margin in the first quarter 2021, with our benchmark SERM in negative territory. We are currently estimating a change of cash flow from our refining business of approximately €160 million per each one-dollar change in the SERM compared to the assumption for 2021 of $3.8 per barrel.

For planning purposes, management assumed a EUR/USD exchange rate in the range of 1.19 – 1.23 U.S. dollars per euro in the 2021-2024 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. We note that in the first quarter of 2021 the EUR/USD exchange rate was approximately 1.2 and has appreciated significantly, year-on-year; this trend will reduce the cash flow of the Eni’s E&P segment compared to the previous year.

See “Item 3 – Risk factors”.

The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, political instability in Libya and other countries, crude oil and natural gas prices; demand for oil&gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to “Item 3 – Risk factors”.

Off-balance sheet arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in “Item 18 – Note 27 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments under take-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 27 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”.

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Contractual obligations

The amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

	Total		2021		2022		2023		2024		2025		2026 and thereafter
Total debt		33,332		7,003		2,137		3,985		2,541		3,143		14,523
Long-term finance debt		23,695		1,697		1,518		3,469		2,049		2,730		12,232
Short-term finance debt		2,882		2,882
Lease liabilities		4,984		815		593		503		442		413		2,218
Fair value of derivative instruments		1,771		1,609		26		13		50				73
Interest on finance debt		3,347		502		473		461		387		360		1,164
Interest expense for lease liabilities		1,871		295		252		219		192		165		748
Guarantees to banks		1,072		1,072
Decommissioning liabilities(1)		11,973		400		237		202		425		276		10,433
Environmental liabilities		2,263		383		323		267		255		196		839
Purchase obligations(2)		103,654		8,041		7,644		7,342		8,150		8,613		63,864
Natural gas to be purchased in connection with take-or-pay contracts(3)		99,417		6,196		6,852		6,809		7,691		8,392		63,477
Natural gas to be transported in connection with ship-or-pay contracts(3)		2,902		893		519		480		439		212		359
Other purchase obligations		1,335		952		273		53		20		9		28
Other obligations(4)		108		2										106
of which:
– Memorandum of intent relating to Val d’Agri		108		2										106
TOTAL		157,620		17,698		11,066		12,476		11,950		12,753		91,677

(1)

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

(2)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.

(3)

Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay or ship-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Global Gas & LNG Portfolio” and “Item 3 – Risk Factors – Risks specific to the Company’s gas business in Italy”.

(4)

In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to provisions for employee benefits (See Note 21 to the Consolidated Financial Statements).

The table below summarizes Eni’s capital expenditures commitments for property, plant and equipment as of December 31, 2020. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown below.

	Total		2021		2022		2023		2024		2025 and subsequent years
	(€ million)
Committed projects		14,675		4,264		3,983		2,890		2,204		1,334

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 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 well as cash reserves and cash on hand to meet currently foreseeable borrowing requirements. The Group cash reserve consists of cash on hand and very liquid financial assets (short-term deposits and held-for-trading securities). This cash 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 24-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – Note 27 of the Notes on Consolidated Financial Statements”.

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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, 2020:

Name	Position	Year elected or appointed		Age
Lucia Calvosa	Chairman		2020		59
Claudio Descalzi	CEO		2014		65
Ada L. De Cesaris	Director		2020		61
Filippo Giansante	Director		2020		53
Pietro A. Guindani	Director		2014		62
Karina A. Litvack	Director		2014		58
Emanuele Piccinno	Director		2020		47
Nathalie Tocci	Director		2020		43
Raphael Louis L. Vermeir	Director		2020		65

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 elected by the ordinary Shareholders’ Meeting held on May 13, 2020 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, 2022.

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.

Lucia Calvosa, Claudio Descalzi, Ada Lucia De Cesaris, Filippo Giansante, Emanuele Piccinno, and Nathalie Tocci were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina A. Litvack and Raphael Louis L. Vermeir were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Lucia Calvosa as the Chairman of the Board of Directors and, on May 14, 2020, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.

Four Directors out of nine, including the Chairman, 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.

Lucia Calvosa was born in Rome and has been Chairman of Eni’s Board since May 2020. She has an honours degree in Law from the University of Pisa and is Professor of Commercial Law at the same university. She has been registered with the Pisa Bar since 1987 and works as a lawyer dealing with specialised aspects of corporate or bankruptcy law. She is currently an independent director in the board of CDP Venture Capital Sgr SpA and Banca Carige SpA and Chairman of the board of directors of Agi SpA – Eni Group. She is also a member of the General Council of the Giorgio Cini Foundation and of the Board of Directors of Fondazione Eni Enrico Mattei (FEEM). She is a member of the Italian Corporate Governance Committee.

Experience

She was Chairman of Cassa di Risparmio of San Miniato SpA and in that capacity, she was also member of the Banking Companies committee and Director of the Italian Banking Association (ABI). She served as independent director and Chairman of the Control and Risk Committee of Telecom Italia SpA. She also served as independent director of SEIF SpA and Banca Monte dei Paschi di Siena SpA. She was a member of the Commission for the National Scientific Qualification for first and second-level university professors in sector 12/ b1 – Commercial Law. She was a member of the Bankruptcy Procedures and

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Corporate Crisis Commission of the National Bar Council. She carried out studies and research for several years at the Institut fur ausländisches und internationales Privat und Wirtschaftsrecht of the University of Heidelberg and has participated with reports and speeches in numerous conferences. In addition to many publications in leading legal journals and collective works, she has published three monographs on corporate and bankruptcy matters and has contributed to leading accredited manuals and commentaries on accounting issues. She has received numerous awards. In 2005, she was awarded the Order of the Cherubino, by the University of Pisa, for her contribution to increasing the University’s standing for its scientific and cultural achievements and for her contribution to the life and operation of the University. In 2010 she was awarded a UNESCO medal for having contributed to developing and disseminating the Italian artistic culture in the spirit of UNESCO. In 2012 she was awarded the honour of Cavaliere dell’Ordine “al merito della Repubblica Italiana”. In 2015 she received the “Ambrogio Lorenzetti” award for good corporate governance, for having been able, as a Director, to introduce scientific rigour and the value of independence in highly complex and competitive business environments.

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.

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 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. He graduated in physics in 1979 from the University of Milan.

Ada Lucia De Cesaris was born in Milan in 1959 and has been a Director of Eni since May 2020.

She is currently a partner at Studio Legale Amministrativisti Associati (Ammlex), where she advises clients on city planning and environmental issues for private and publicly owned assets; supports investors and developers in proceedings with public authorities; engages in consulting, training and support activities on matters relating to energy sustainability and the management of environmental critical issues.

In 1986 she contributed to research on the problems of energy governance, within the “Finalised Energy Programme”. Since 2000 she has been a member of the Scientific Committee of the Rivista Giuridica dell’Ambiente.

Since February 2016 she has been a member of the Research Institute on Public Administration (IRPA).

Since December 2019 she has been a member of the Board of Directors of CDP Immobiliare S.r.l.

Since May 2020 she has been a member of the Advisory Committee of the Back2Bonis Fund.

Experience

From 1985 to 1988 she worked with Massimo Annesi, Vice president of Associazione per lo Sviluppo del Mezzogiorno (Southern Development Association), on a comprehensive survey of all legislation concerning Southern Italy from 1970; she participated in the realization of the project Rivista Giuridica del Mezzogiorno, published by il Mulino, heading the editorial support staff. She also worked with the Rivista Giuridica dell’Ambiente (Legal Journal of the Environment). From 1989 to 2003, on behalf of CIRIEC, she carried out a research on environment protection legislation in Japan. From 2000 to 2011 as an independent consultant, she coordinated research activities of the legal department of the Environmental Insitute (Istituto per l’Ambiente). She participated in research activities for the Lombardy Foundation for

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the Environment, in particular regarding waste, air and accident risks. She produced studies and papers on environmental impact assessment both with regard to waste and activities at risk. She was a Professor of Environmental Law at the Faculty of Environmental Sciences at the University of Insubria.

From 2011 to 2015 she was deputy mayor of the Municipality of Milan and Councillor with responsibility for town planning, private construction and agriculture. From 2015 to 2017 she was partner at the law firm Studio NCTM.

From 2016 to 2019 she was member of the Board of Directors of Arexpo SpA. She has authored numerous publications on the environment, energy and waste management. She graduated with honours in Law and received a scholarship and pursued an advanced course in “Economic development” with UNIONCAMERE.

Filippo Giansante was born in Avezzano (AQ) in 1967 and has been a Director of Eni since May 2020. He is currently General Manager – Head of the Public Heritage Development Department of the Italian Treasury.

He is a member of the Board of Directors of SACE SpA.

Experience

From 1994 to 1996 he was Treasury Department Officer in International Affairs. In 1997 he was assistant to the Executive Director of the European Bank for Reconstruction and Investment; he was Director – International Financial Relations, Department of the Treasury, where he dealt with issues relating to the debt of developing countries as well as bilateral financial relations (2002 – 2011). With the same role he coordinated the G7/G8/G20, and supervised institutional relations with the International Monetary Fund (2011-2017).

He was a Director of Simest SpA (2003-2005) and SACE SpA (2004-2007).

He was Alternate Governor for Italy for the World Bank, the Asian Development Bank, the African Development Bank, the European Bank for Reconstruction and Development and the Caribbean Development Bank, as well as being a Board Member for Italy at the European Investment Bank (2015-2017).

He was a member of the Administrative Council for Italy at the Council of Europe Development Bank (2016-2017). Furthermore, he was Executive Director for Italy of the European Bank for Reconstruction and Development.

He graduated with honours in Political Science from the Sapienza University of Rome.

Pietro A. Guindani is a Director elected from the slate of candidates submitted by a group of Italian and foreign institutional Investors. He was born in Milan in 1958 and has been Director of Eni since May 2014. Since July 2008 he has been Chairman of the Board of Directors of Vodafone Italia SpA, where between 1995-2008 he was Chief Financial Officer and subsequently Chief Executive Officer. He previously held positions in the Finance Departments of Montedison and Olivetti and started his career in Citibank after graduating in Business at the Bocconi University in Milan. He is currently also a Board member of the Italian Institute of Technology and Cefriel-Polytechnic of Milan. He is Board Member of Confindustria and Member of the Executive Board of Confindustria Digitale; he is President of Asstel-Assotelecomunicazioni and Vice President responsible for Universities, Innovation and Human Capital of Assolombarda.

Experience

He was also Director of Société Française du Radiotéléphone – SFR S.A. (2008-2011), Pirelli & C. SpA (2011-2014), Carraro SpA (2009-2012), Sorin SpA (2009-2012), Finecobank SpA (2014-2017) and Salini-Impregilo SpA (2012-2018).

Karina A. Litvack was born in Montreal in 1962 and has been a Director in Eni since May 2014. She is currently non-Executive Chairman of the Sustainability Board Committee of Viridor Waste Management Ltd, a member of the Board of Governors of the CFA Institute, a member of the Board of Business for Social Responsibility, a member of the Advisory Council for Transparency International UK and a member of the Senior Advisory Panel of Critical Resource. She is founder and executive member of the Board of Chapter Zero Limited.

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Experience

From 1986 to 1988 she was a member of the Corporate Finance team of PaineWebber Incorporated. From 1991 to 1993 she was a Project Manager of the New York City Economic Development Corporation. In 1998 she joined F&C Asset Management plc where she held the position of Analyst Ethical Research, Director Ethical Research and Director Head of Governance and Sustainable Investments (2001-2012). She was also a member of the Board of the Extractive Industries Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012). From 2003 to 2014 she was a member of the CEO Sustainability Advisory Panel of Lafarge SA; from January 2008 to December 2010 she was a member of the CEO Sustainability Advisory Panel of Veolia SA; from January to December 2010 she was a member of the CEO Sustainability Advisory Panel of ExxonMobil and Ipieca; from January 2010 to November 2017 she was a member of the CEO Sustainability Advisory Panel in SAP AG. From January 2015 to May 2019 she was a member of the Board of Yachad. She graduated in Political Economy at the University of Toronto and in Finance and International Business from Columbia University Graduate School of Business.

Emanuele Piccinno is a Director elected from the slate of candidates submitted by the Ministry of economy and finance. Emanuele Piccinno was born in Rome in 1973 and has been a Director of Eni since May 2020. Expert in the sustainability of energy systems, he has carried out consulting and training activities in the energy and environmental field since 2003.

Experience

Member of the Italian Chapter of the International Solar Energy Society, a non-profit association for the promotion of the use of Renewable Energy Sources from 2004 to 2008, and of the Research Unit “Innovation, Energy and Sustainability” in the Interuniversity Research Centre for Sustainable Development, Sapienza University of Rome from 2004 to 2013. He was also technical director of E-cube Srl, an energy and environmental services company in Rome from 2009 to 2013. From 2011 to 2013 he was Professor at the Università della Tuscia in Viterbo; from he was a consultant-senior researcher at the University Consortium of Industrial and Managerial Economics (CUEIM) in Rome.

He also served as a legislative consultant for energy and transport to the Chamber of Deputies during the 17th Legislature.

From July 2018 to September 2019 he was head of the support staff of the Undersecretary of State for Energy at the Ministry for Economic Development; from October 2019 to May 2020 he was Councillor for Energy Issues at the Ministry for Economic Development.

He graduated in Economics and Trade from the “Sapienza” University of Rome. He also obtained a PhD in “Sustainable development and international cooperation – energy and environmental technologies for development” from the same university, as well as having followed an advanced training course in “Environmental certification in the European Union”.

Nathalie Tocci was born in Rome in 1977 and has been a Director of Eni since May 2020. Since 2017 she has been Director of the Istituto Affari Internazionali. Since 2015 she has been Special Advisor to the European Union High Representative for Foreign and Security Policy and Vice President of the European Commission Federica Mogherini and currently Josep Borrell. Since 2015 she has been Honorary Professor of the University of Tübingen. She is a member of the Board of the “Centre for European Reform”, the “Jacques Delors Centre”, the “Real Instituto Elcano” and the “Nuclear Threat Initiative”; a member of the scientific committee of the Fondation pour la Recherche Stratégique, the European Leadership Network; a member of the Advisory Board of Europe for Middle East Peace (EuMEP), and of European Council for Foreign Relations. She is a member of the advisory editorial board of the reviews Open Security/Open Democracy, International Politics, The Europe-Asia Journal, The Cyprus Review; a member of the Advisory Board of Mediterranean Politics and of The International Spectator.

Experience

From 1999 to 2003 she was Research Fellow within the Wider Europe Programme of the Centre for European Policy Studies in Brussels. From 2003 to 2007 she was Jean Monnet Fellow and Marie Curie Fellow at the European University Institute. In 2005 she was Analyst for Cyprus at the International Crisis Group.

From 2006 to 2010 she was Research Manager at the Istituto Affari Internazionali in Rome.

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From 2007 to 2009 she was an Associate Fellow for EU foreign policy at the Centre for European Policy Studies in Brussels. From 2009 to 2010 she was Senior Fellow for Turkey’s relations with the United States, the European Union and the Middle East at the Transatlantic Academy in Washington. From 2012 to 2014 she was member of the Board of Directors of the University of Trento. In 2014 she was Councillor for international strategies of the Minister of Foreign Affairs, Federica Mogherini (June-November 2014).

From 2013 to 2020 she was member of the Board of Directors of Edison SpA. In 2014 she was member of the NATO Transatlantic Bond Experts Group. From 2015 to 2019 she was Special Advisor to the High Representative of the European Union for Foreign Affairs and Security Policy and Vice-President of the European Commission, Federica Mogherini, on whose behalf she drafted the EU’s global strategy and worked on its implementation.

She has written a monthly editorial for “Politico” magazine, frequently contributes to editorials, comments and interviews with various media, including the BBC, CNN, Euronews, Sky, Rai, New York Times, Financial Times, Wall Street Journal, Washington Post and El País. She has received several awards from the European Commission and university institutes, besides obtaining various scholarships, including the University College of London scholarship for academic excellence.

She graduated with honours from University College, Oxford in Politics, Philosophy and Economics.

Raphael Louis L. Vermeir is a Director elected from the slate of candidates submitted by a group of Italian and foreign institutional Investors. Raphael Louis L. Vermeir was born in Merchtem (Belgium) in 1955 and has been a Director of Eni since May 2020. He is currently an independent advisor for the mining and oil industry. Since 2016 he has been Senior Advisor for AngloAmerican, Energy Intelligence and Strategia Worldwide. He serves as Trustee of St Andrews Prize for the Environment and the Classical Opera Company in London, as well as board member of Malteser International. He is Fellow of the Energy Institute and the Royal Institute of Naval Architects, and has been Chairman of IP week for the last five years.

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 Louis L. 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.

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.

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Senior Management

The table below sets forth the composition of Eni’s Senior Management as at December 31, 2020. 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		39		65
Massimo Mondazzi	Energy Evolution Chief Operating Officer(1)	2020		28		57
Alessandro Puliti	Natural Resources Chief Operating Officer	2020		30		57
Francesco Gattei	Chief Financial Officer	2020		25		51
Claudio Granata	Human Capital & Procurement Coordination Director	2020		37		60
Francesca Zarri	Technology, R&D & Digital Director	2020		24		51
Stefano Speroni	Legal Affairs & Commercial Negotiation Director	2020		2		58
Marco Petracchini	Internal Audit Director(2)	2011		21		56
Roberto Ulissi	Corporate Affairs and Governance Director and Board Secretary and Corporate Governance Counsel(3)	2006		14		58
Erika Mandraffino	External Communication Director	2020		14		47
Lapo Pistelli	Public Affairs Director	2020		5		56
Luca Franceschini	Integrated Compliance Director(4)	2016		29		54
Jadran Trevisan	Integrated Risk Management Director(5)	2016		20		59

(1)

The rule of Energy Evolution Chief Operating Officer is held by Giuseppe Ricci appointed as of January 1, 2021, replacing Massimo Mondazzi.

(2)

Effective April 1, 2021, Mr. Gianfranco Cariola took over as Internal Audit Director.

(3)

Luca Franceschini has been appointed Board of Directors and Board Counsel as of January 1, 2021, replacing Roberto Ulissi.

(4)

Luca Franceschini has also been appointed Board of Directors and Board Counsel as of January 1, 2021.

(5)

Grazia Fimiani has been appointed Integrated Risk Management Director as of January 1, 2021, replacing Jadran Trevisan.

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, are members of the Management Committee5, 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 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, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer (in his capacity as Director in charge of the internal control and risk management system), following consultation with the Board of Statutory Auditors and the Nomination Committee and with the favorable opinion of the Control and Risk Committee.

The Board Secretary and Corporate Governance Counsel6 is appointed by the Board of Directors upon a proposal of the Chairman.

The Committee includes also the Chairman of the Board, the CEOs of certain Eni’s subsidiaries, the Director of Upstream business, the Director of Refining & Marketing and from March 26 2021 also the Head of Accounting and Financial Statements and the Head of Planning and Control.

Board of Directors and Board Counsel as of January 1, 2021.

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

Senior Managers

Massimo Mondazzi was born in Monza in 1963. He was appointed Chief Operating Officer of Energy Evolution in Eni on July 1, 2020. He joined Eni in 1992 after acquiring a great deal of professional experience in industrial companies and also as a management consultant. He worked in the Administration and Control area of the Exploration and Production Division until 2006, becoming head of the division From 2006 to 2009 he was Director of Planning and Control for the Eni Group, before returning to E&P as Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration and Production division, to the launch of new development projects and to Eni’s entry into new countries. From December 5, 2012 until July 31, 2020 he was the Chief Financial Officer of Eni and Manager charged with preparing the company’s financial reports pursuant to Article 154-bis of Legislative Decree No. 58/1998. From 2014 until September 2016, alongside his role as Eni’s Chief Financial Officer, he was also responsible for Eni’s Integrated Risk Management department. He graduated in Economics and Business Administration from Bocconi University Milan in 1987.

Alessandro Puliti was born in Florence on June 23, 1963. He was appointed Chief Operating Officer Natural Resources of Eni on July 1, 2020. He joined Agip SpA’s Reservoir Department in 1990 as a Reservoir Geologist and was involved in the study of reservoirs in Africa and Italy. His international professional career started in 1998, when he moved to Aberdeen to fill the position of Assistant Operated Asset Manager of Agip UK, where he gained operational experience in complex contexts. After returning to Italy in 2002, he was appointed Reservoir and Drilling and Completion Manager in the Val D’Agri project. In 2003 he was posted to Egypt as IEOC’s Development and Operations Manager and subsequently covered increasingly more complex managerial roles, first as General Manager and Managing Director of Petrobel and later as General Manager of IEOC. In 2009 he moved back to Italy to take on the role of Regional Management Russia and North Europe Vice President. In 2010, he moved to Stavanger, where he held the dual role of Eni Norge’s Managing Director and Regional Management Russia and North Europe Vice President. In 2012 he returned to the HQ Operations Department, first as Senior Vice President Petroleum Engineering, Production and Maintenance and then as Senior Vice President Drilling and Completion and Deputy Operations. In October 2015 he was appointed Reservoir & Development Projects Executive Vice President. In September 2018 he was appointed Chief Development, Operations & Technology Officer and then Chief Upstream Officer on July 1, 2019. He graduated with Honors in Geology from the University of Milan and earned the MEDEA Master in Energy and Environmental Management and Economics from “Scuola Mattei”. He is the author of several papers on reservoirs and drilling presented at international conferences.

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.

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 has also been member of the Board of Directors of AGI since

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September 2020 and member of the Board of Directors of FEEM 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.

Francesca Zarri was born on June 22, 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. Since November 2020 she has been the President of EniProgetti.

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.

Stefano Speroni was born in Milano in 1962. He was appointed Director Legal Affairs and Commercial Negotiations of Eni on July 1, 2020. Stefano Speroni 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

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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.

Marco Petracchini was born in Rome in 1964. He was appointed Director Internal Audit of Eni on July 1, 2020. He is also a member of the Supervisory Board and Secretary of the Committee for Control and Risk of Eni SpA. He holds the following international qualifications: Certified Internal Auditor (CIA), Certified Fraud Examiner (CFE) and Certified Risk Management Assurance (CRMA). He is currently a Chairman of AIIA (Association of Italian Internal Auditors); from February 1, 2021 he was also appointed Chairman of the Board of Directors of Versalis SpA. He graduated Cum Laude with a degree in economics from La Sapienza University in Rome in 1989. After graduation, he was hired by Esso Italiana where he held various positions in the IT, Finance and Auditing sectors. He joined Eni in 1999 in the Internal Audit Department, gradually taking on positions of increasing responsibilities: Head of Downstream Audit activities and Head of Support Process Audit activities (in particular IT and Fraud Audit). He is also a member of the Watch Structure of Eni SpA and Secretary of the Control and Risk Committee of Eni SpA. He holds international qualifications as well, in detail: Certified Internal Auditor (CIA), Certified Fraud Examiner (CFE), Certified Risk Management Assurance (CRMA). He is currently a Board Member of AiiA (Italian Internal Auditors Association). He is Eni’s Senior Executive Vice President Internal Audit.

Roberto Ulissi was born in Rome in 1962. He was appointed Director Corporate Affairs and Governance in Eni on July 1, 2020. Since 2006, he has been Senior Executive Vice President of Corporate Affairs and Governance; he was Board member of Eni International BV and Board Secretary of Eni7. Since 2014 he is Corporate Governance Counsel and Company Secretary. He is a Board member and Vice Chairman of Banor SIM. Since May 2018 he has been Coordinator of the Corporate Governance Forum of Company Secretaries. 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 is a board member and Vice Chairman of Banor SIM. 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 (Commission “Vietti”) 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.

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.

He was the Board Secretary of Eni and Corporate Governance Counsel and Company Secretary and a Board Member of Eni International BV until December 2020.

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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. Having 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). As an Italian MP, he was member of the Committees on Constitutional Affairs, European Affairs and on International Affairs. As a MEP in Brussels, he worked at the Economic and Monetary Affairs and Foreign Affairs Committees. During this period, he has also been the President of the EU-South Africa Delegation and a member of the Italian Delegation to the OSCE, where he conducted several monitoring missions in transitional democracies. 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 as Senior Vice President for Strategic Analysis for Business Development Support. He was appointed Executive Vice President of International Affairs since on April 14, 2017. 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. Among other things, he’s a member of the Council of Chatham house, member of the board of the European Council on Foreign Relations (ECFR) and of the Istituto Affari Internazionali (IAI), member of the WE – World of Energy editorial committee and of the EastWest scientific committee. He’s Vice Chairman of OME (Observatoire Mediterranéen de l’Energie) and member of the IRENA’s (International Renewable Energy Agency) Global Commission on the Geopolitics of Energy Transformation. As a journalist, he regularly publishes in various newspapers issues related to European and international affairs and on specialized magazines, such as Limes. He authored several publications: in his last book, Il nuovo sogno arabo – Dopo le rivoluzioni, Feltrinelli 2012, he analyses the origin and challenges of the ‘Arab Spring’ and its impact on the geo-political scenario in North Africa and the Middle East.

Luca Franceschini8 was born in Milan in 1966. Since 2016 he was Executive Vice President of Integrated Compliance in Eni. He was appointed Director Integrated Compliance on July 1, 2020. Attorney registered with the Ordine degli Avvocati (the Italian Bar association) of Rome, he is a member of the Board of the European Chief Compliance and Integrity Officers Forum (ECCIOF). After graduating in Law from the University of Milan, he first joined Eni in 1991 in the legal department of the then Agip SpA, 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 liberalisation 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 Sogit 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. He was also member of the boards of directors of Italgas and Stogit.

In 2017 he was awarded “Compliance Officer of the Year” by the Top Legal Corporate Counsel Awards and the Inhouse Community Awards.

Jadran Trevisan was born in Milan in 1961. Since 2016 Executive Vice President of Integrated Risk Management in Eni; on July 1, 2020 he was appointed Director Integrated Risk Management. After a short period at Gabetti, in 1991 he joined the Fininvest Group, where he was involved in financial communications and was part of the project for the listing of Mediaset for which, in 1995, he became the Investor Relations Manager. In 2000 he joined Eni as head of Investor Relations, where, in addition to participating in a number of significant extraordinary operations (the listing of Snam Rete Gas, the de-listing of Italgas), he oversaw relations with institutional investors. In 2006 he was appointed head of Business Strategy at Eni’s E&P division, where he was involved in the acquisition of significant assets and

Since January 2021 he is also the Board Secretary of Eni and Board Counsel.

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companies operating in the upstream sector. In 2008 he was appointed CFO of the recently acquired subsidiary Distrigas, where, for the following three years, he was engaged in consolidating and aligning the company’s business and financial processes with those of Eni and rationalising the company structure. In 2011 he was part of the project for the creation of Eni Trading & Shipping SpA, becoming its Senior Vice President for Operations & Control. From the end of 2012 until July 2015 he was Senior Vice President Credit and in August 2015 he was appointed Senior Vice President for Integrated Risk Management. Since September 12, 2016 in his role as Executive Vice President Integrated Risk Management he reports directly to the Chief Executive. Since March 18, 2019, he is also responsible of identification, evaluation and monitoring Eni industrial and contractual risks processes. He has a degree in philosophy and a Master in business administration from SOGEA, the management school of Confindustria Liguria.

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, 2020, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief Executive Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the 2020 period, filled said roles, even if only for a fraction of the year), was €1,332 thousand.

Name

(€ thousand)

Descalzi Claudio

Chief Executive Officer

376

Senior managers(a)

956

TOTAL

1,332

(a)

No. 22 managers.

Board practices9

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. As of December 31, 2020 Eni complied with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) approved by Italian Corporate Governance Committee, lastly amended on July 2018 (hereinafter “Corporate Governance Code 2018” or “Code 2018”). On December 23, 2020 Eni’s Board of Directors decided to adopt the new Corporate Governance Code approved by the same Committee on January 2020 (hereinafter “new 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 14, 2020, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, in addition to those that cannot be delegated by law, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board.

In the same resolution, the Board of Directors resolved to confer to the Chairman a major role in internal controls and non-operational functions. In particular, with reference to Internal Audit, the Board

The information contained in this chapter is updated to December 31, 2020 and for specific aspects, expressly indicated, up to the date of approval of this Report.

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of Directors resolved that, in accordance with the Code 2018, 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 her statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer.

On the same date (May 14, 2020), the Board of Directors appointed the Secretary of the Board of Directors and entrusted him with the role of Corporate Governance Counsel.

Finally, on December 23, 2020 (effective from January 1, 2021), the Board appointed a new 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.

On May 14, 2020, the Board reserved to itself the strategic, operational and organizational powers briefly described below. Accordingly, the Board:

•

defines the system and rules of Corporate Governance for the Company and the Group;

•

establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets;

•

expresses the general criteria for determining the maximum number of offices that a Director may hold in other companies;

•

delegates and revokes the powers of the CEO and the Chairman, establishing the limits and procedures for exercising those powers and determining the compensation associated with these duties;

•

establishes the basic structure of the organizational, administrative and accounting arrangements of the Company (including the internal control and risk management system), of its strategically important subsidiaries and of the Group as a whole. It evaluates the adequacy of these arrangements;

•

establishes the guidelines for the internal control and risk management system, so that the main risks facing the Company and its subsidiaries are correctly identified and adequately measured, managed and monitored, determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives. It sets the financial risk limits of the Company and its subsidiaries. It also examines the main business risks, which are identified taking into account the characteristics of the activities carried out by the Company and its subsidiaries and which are reported by the Chief Executive Officer at least quarterly. Moreover, it evaluates, every six months, 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 the system’s effectiveness;

•

approves at least annually the Audit Plan drawn up by the Director of the Internal Audit Department. It also evaluates 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;

•

defines the strategic guidelines and objectives of the Company and the Group, including sustainability policies. It examines and approves the budgets and strategic, industrial and financial plans of the Group, periodically monitoring their implementation, as well as agreements of a strategic nature for the Company. It examines and approves the plan for the Company’s non-profit activities and approves operations not included in the plan whose cost exceeds €500,000;

•

examines and approves the annual financial report (which includes Eni’s draft Financial Statements and the Consolidated Financial Statements) and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report and any additional periodic statements or reports in accordance with applicable regulations;

•

receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers;

•

receives a report from the Board’s internal committees on at least a semi-annual basis;

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•

assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts;

•

evaluates and approves transactions of the Company and its subsidiaries with related parties provided for in the procedure approved by the Board10, as well as transactions in which the CEO has an interest;

•

evaluates and approves any transaction executed by the Company and its subsidiaries that has a significant impact on the Company’s strategy, performance or financial position;

•

appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the Director of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of people of the relevant structures responsible for institutional investors and shareholder relations;

•

examines and approves the Report on remuneration policy and remuneration paid to be presented to the Shareholders’ Meeting. It also defines the remuneration of Directors with delegated powers and with special duties, establishes the objectives – and verifies their achievement – applicable to the variable remuneration of Directors with delegated powers and incentive plans and implements compensation plans based on shares or other financial instruments approved by the Shareholders’ Meeting;

•

resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries;

•

formulates the proposals to present to the Shareholders’ Meeting; and

•

examines and resolves 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 Article 23.2 of the By-laws, the Board also resolves on mergers and proportional spin-offs of companies in which Eni’s shareholding is at least 90%; the establishment and closing of branches; and the amendment of the By-laws to comply with the provisions of law.

In accordance with the By-laws, the Chairman and the Chief Executive Officer have the power to represent the Company.

Directors’ independence

On the basis of statements made by the Directors and other information available to the Company, during its meeting of May 14, 2020, the Board of Directors determined that Chairman Calvosa and Directors De Cesaris, Guindani, Litvack, Piccinno, Tocci and Vermeir satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors De Cesaris, Guindani, Litvack, Tocci, and Vermeir have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code 2018. Chairman Calvosa, in compliance with the Corporate Governance Code 2018, could not be deemed independent as she is a significant representative of the Company.11

At the last assessment carried out on May 2020, the Board of Directors also evaluated that the relationships: (i) between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative pursuant to the Corporate Governance Code 2018; (ii) between Eni and a law firm whose partner is a relative of Director De Cesaris, and (iii) between Eni and Istituto Affari Internazionali – IAI (a private, independent non-profit think tank), of which Director Tocci is General Manager, are not significant for the purpose of assessing the independence of these Directors, having regard to the nature and the amounts of these relationships. 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.

The Board of Directors, on November 18, 2010, approved the Management System Guideline (MSG) “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, which has been applied since January 1, 2011, to ensure transparency and substantial and procedural fairness of transactions with related parties. The Board modified this MSG on January 19, 2012 and, lastly, on April 4, 2017.

Although the Chairman of the Board of Directors is a non-executive Director, the Code 2018 treats her as a significant representative of the Company (Application Criterion 3.C.2 of the Corporate Governance Code 2018). However, under the new Corporate Governance Code, the Chairman of the Board can be assessed as independent if none of the circumstances set forth in the new Code, that jeopardise, or appear to jeopardise, the independence of a Director, occurs.

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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.

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 2018. 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 2018.

The Committees recommended by the Code 2018 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 and Remuneration Committee meetings and may participate in other Committees’ meetings. Furthermore, Committees may invite other persons to attend the meetings in relation to individual items on the agenda.

The CEO and the Chairman of the Board may attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they may attend Control and Risk Committee meetings, unless matters relating to them are discussed. Finally, they may attend Remuneration Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their remuneration12.

The Board Secretary and Corporate Governance 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 14, 2020.

Remuneration Committee

Members: Nathalie Tocci (Chairman), Karina A. Litvack, Raphael Louis L.Vermeir.

The Remuneration Committee may be composed of three to four non-executive, independent Directors. All the members possess adequate professional requirements and expertise for carrying out the duties assigned to the Committee. The Committee’s rules require that at least one of its members possess adequate knowledge and experience of financial matters or remuneration policies, as assessed by the Board at the time of his or her appointment.

Established by the Board of Directors for the first time in 1996, in accordance with the By-laws, the Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee:

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

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submits the Remuneration Report and in particular the Remuneration Policy for Directors and Managers with strategic responsibilities to the Board of Directors for approval, prior to its presentation at the Shareholders’ Meeting called to approve the year’s financial statements, in accordance with the time limits set by applicable law;

periodically evaluates the adequacy, overall consistency and effective implementation of the Policy, formulating proposals, as appropriate, for approval by the Board of Directors;

presents proposals for the remuneration of the Chairman and the Chief Executive Officer, including the various components of compensation and benefits;

presents proposals for the remuneration of Board Committee members;

having examined the Chief Executive Officer’s input, proposes general criteria for the compensation of Managers with strategic responsibilities, the annual and Long-Term incentive plans, including equity-based plans, sets performance objectives and assesses performance against them, thereby determining the variable awards due to Executive Directors pursuant to the implementation of the approved incentive plans;

monitors execution of decisions taken by the Board;

reports at the first available meeting of the Board of Directors through the Committee Chairman 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 June 30, at the Board meeting designated by the Chairman of the Board of Directors.

Furthermore, in exercising its functions, the Committee may issue opinions as required by Company procedures in relation to operations with related parties, in accordance with specified procedures.

The Committee performs its duties pursuant to an annual plan and may access the information and Company managers as necessary to perform its duties, and to avail itself of independent external advisors within the terms and budget limits set by the Board of Directors.

The Committee also reports on its procedures at the Annual Shareholders’ Meeting called to approve the financial statements through its Chairwoman or other duly designated member, with the goal of establishing and appropriate channel for dialogue with shareholders and investors.

During 2020, the Remuneration Committee met a total of ten times, with an average attendance of 100% of its members and an average duration of 2 hours and 10 minutes. At least one member of the Board of Statutory Auditors participated in each meeting, while the Chairman of the Board of Statutory Auditors attended all meetings. At the invitation of the Chairman of the Committee, managers of the Company and advisors participated in specific meetings, to provide information and clarifications requested by the Committee to pursue the analysis conducted.

Earlier in the year, the Committee focused its activities in particular on the following topics:

the periodic evaluation of Remuneration Policy implemented in 2019, also with a view to developing new Policy Guidelines for the 2020-2023 term, electing to maintain the structure and the remuneration criteria for Directors and Managers with strategic responsibilities established in the previous term;

ii.

the review of the Company’s 2019 results for the purpose of implementing the Short- and Long-Term variable incentive plans, using a predetermined gap analysis method approved by the Committee in order to neutralize the positive or negative impact of exogenous factors and enable the objective assessment of the performance achieved;

iii.

definition of 2020 performance targets relevant to the variable incentive plans;

iv.

definition of the proposal for the implementation of the Short-Term Incentive Plan with deferral for the Chief Executive Officer and General Manager;

finalizing the new 2020-2022 Long-Term Share Incentive Plan for the purposes of its approval by the Board of Directors and presentation to the Shareholders Meeting of May 13, 2020;

vi.

update of remuneration benchmark studies for the purpose of defining the proposals for Remuneration Policy Guidelines for the 2020-2023 term for Directors with Delegated powers, Non-Executive Directors for participation in Board Committees, the members of the Board of Statutory Auditors and other key management personnel.

vii.

analysed Eni’s 2020 Remuneration Report prepared pursuant to Art. 123-ter of Italian Legislative Decree 58/98 and Art.84-quater of Consob Issuers Regulation, for the purpose of subsequent

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approval by the Board and presentation to the Shareholders Meeting of May 13, 2020, invited to vote on a binding resolution regarding the first section of the Report and a non-binding resolution on the second section in accordance with applicable regulation;

viii.

review of the outcome of the meeting conducted with the main institutional investors and proxy advisors before the 2020 Shareholder’s Meeting, in order to maximize shareholder consensus on the 2020-2023 Remuneration Policy and on the 2020-2022 Long-Term Share Incentive Plan; these meetings where also attended by the Chairman of the Committee underscoring the importance that the Committee gives dialogue with shareholders;

ix.

risk and scenario assessment activities, assessment of emerging developments in most relevant remuneration-related issues, examination of the composition of shareholders, including assessment of the characteristics of the retail shareholder segment, as well as examination of voting recommendations issued by leading proxy advisors and of related voting projections, which were performed with the supporting of a leading consulting firm.

Following the appointment of corporate bodies, the Committee was called to formulate proposals on the remuneration of Directors with delegated powers for the new 2020-2023 term as well as define remuneration of Non-Executive Directors for participation in Board Committees, to be submitted for approval by the Board of Directors, subject to a non-binding opinion of the Board of Statutory Auditors, in accordance with the Policy approved for the term by the Shareholders’ Meeting held on May 13, 2020 .

Furthermore, the Committee performed training activities (“board induction”) with the competent corporate functions with the aim of providing the new Directors with precise knowledge of its main duties and the cycle of activities of the Remuneration Committee, as well as the structure, general criteria and remuneration levels provided for by the Eni Remuneration Policy.

In the second half of the year, the Committee examined the 2020 Shareholders’ Meeting vote results, with regard to the Eni Remuneration Report, compared to the results of the major Italian and European listed companies and of the Eni’s Peer Group.

As regards further relevant activities carried out, the Committee:

—

finalized the proposal (2020 award) for the implementation of the 2020-2022 Long Term Share Incentive Plane for the Chief Executive Officer and General Manager and for key management personnel;

—

examined the general criteria for defining the 2021 engagement plan and carried out a first cycle of meetings with main proxy advisor firms;

—

updated the “Implementation criteria for the clawback principle envisaged by the Eni Remuneration Policy” approved on 12 March 2015 and modified on 26 October 2017, to adapt its contents to the 2020-2023 Eni policy, in particular concerning the applicability of the malus clauses;

—

monitored developments in the legislative framework and market standards concerning the reporting of remuneration-related information, with a specific focus on the implementing measures of the EU Directive 828/2017 (SRD II), as well as developments in the corporate governance codes, at a national and European level, and in the voting policies of leading proxy advisors and institutional investors, also with a view to understanding developments stemming from the COVID-19 pandemic.

The Committee scheduled seven meetings for 2021, three of which have already been held as of the date of approval of this Report.

Control and Risk Committee

Members: Pietro Guindani (Chairman), Ada Lucia De Cesaris, Nathalie Tocci and Raphael Louis L. Vermeir.

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The Control and Risk Committee is entrusted with supporting, on the basis of an appropriate control process, the Board of Directors in evaluating and making decisions concerning the internal control and risk management system and in approving the periodical financial reports. It is entirely made up of non-executive and independent Directors13 who possess the necessary expertise consistent with the duties they are required to perform14.

In particular, at their appointment, the Directors Guindani and Vermeir were identified by the Board as members with “adequate experience in the area of accounting and finance or risk management”, as recommended by the Corporate Governance Code.

The Committee advises the Board of Directors and specifically issues its prior opinion: a) on draft recommendations concerning the guidelines for the internal control and risk management system so that the main risks faced by the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored and also supports the Board in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives; b) on the assessment, performed by the Board of Directors, of the main company risks, identified taking into account the characteristics of the activities carried out by the company or its subsidiaries; c) on 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, at least once every six months 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 internal control and risk management system at the meeting of the Board of Directors indicated by the Chairman of the Board of Directors; d) on the approval, at least once a year, of the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; e) on the description, 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 its evaluation of the overall adequacy of the system itself; and f) on the evaluation of the findings reported by the Audit Firm in any recommendations letter it may issue and in the latter’s additional report, together with any comments from the Board of Statutory Auditors.

The Committee furthermore: a) issues opinions to the Board of Directors on specific aspects concerning the identification of the main risks faced by the Company; b) examines and issues an opinion on the adoption and amendment of the rules on the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or Statutory Auditor holds a personal interest or an interest on behalf of a third party, while performing additional duties assigned it by the Board of Directors, including examining and issuing an evaluation on specific types of transactions, except for those relating to compensation; and c) gives an opinion on 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.

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, prior to their approval by the Board of Directors; b) examines and evaluates Reports prepared by the CFO/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 legally mandated supervision tasks; c) at the 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 of which the Board may have become aware and d) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department

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, a 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.

The Governance system put in place by Eni establishes that at least two members of the Committee – and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.

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andoversees its activities with respect to the duties of the Board of Directors in this area, and on its behalf, of the Chairman, 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.

A favorable opinion of the Committee is required for the approval by the Board of proposals by the Chairman in agreement with the CEO concerning the appointment and the removal and, consistent with the Company’s policies, the structure of the fixed and variable compensation of the Senior Executive Vice President of the Internal Audit Department, as well as on the adequacy of the resources provided to the latter to perform his duties.

The Committee also: a) evaluates, on the occasion of his appointment, whether the Senior Executive Vice President of the Internal Audit Department 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; c) examines the periodic reports prepared by the Senior Executive Vice President of the Internal Audit Department as to whether it contains 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 assesses the appropriateness of the internal control and risk management system. It also examines the reports prepared promptly by the Senior Executive Vice President of the Internal Audit Department on events of particular importance; and d) examines the information received from the Senior Executive Vice President of 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 that perform important roles in the design or operation of the internal control and risk management system; and (ii) circumstances that may affect the maintenance of the independence of the Internal Audit Department and of auditing activities.

The Committee may also ask the Internal Audit Department to perform audits on specific operational areas, providing simultaneous notice to the Chairman of the Board of Statutory Auditors. The Committee also examines and assesses: a) communications and information received from the Board of Statutory Auditors and its members regarding the internal control and risk management system, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports; 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 material or significant situation detected in the performance of its duty; c) information on the internal control and risk management system, including that provided in the course of periodic meetings with the competent Company structures; and d) enquiries and reviews concerning the internal control and risk management system carried out by third parties.

Furthermore, the Committee oversees the activities of the Legal Affairs Department in case of judicial inquiries and proceedings, carried out in Italy and/or abroad, involving the CEO and/or the Chairman of the Company 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 mandate and their scope of responsibility.

The composition and appointment, as well as duties and operational procedures of the Committee, are governed by rules approved by the Board of Directors lastly on June 4, 2020 available to the public at the Company’s website.

Nomination Committee

Members: Ada Lucia De Cesaris (Chairman), Pietro Guindani and Emanuele Piccinno.

The Nomination Committee is made up of non-executive Directors, a majority of whom are independent.

The Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee:

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

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 responsibility and oversees the associated succession plans. Where possible and appropriate, and with due regard to the shareholding structure, the Committee proposes the CEO succession plan to the Board of Directors;

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

proposes candidates to serve as Directors to the Board of Directors in the event one or more positions need to be filled during the course of the financial 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;

proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, taking account of any recommendations received from shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders;

oversees the annual self-assessment program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and deals with the preliminary activity for appointing an external consultant for such self-assessment. On the basis of the results of the self-assessment, the Committee provides its opinions to 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 so that the Board itself can give its opinion to the shareholders prior to the appointment of the new Board;

proposes to the Board of Directors 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, first period, of the By-laws;

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;

periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible;

provides its opinion to the Board of Directors on any activities carried out by the Directors in competition with the Company;

through the Chairman of the Committee, informs the Board of Directors on the main issues examined by the Committee thereof during the first available meeting of the Board; furthermore, the Committee 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 as well as on the adequacy of the appointment system, 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 Senior Executive Vice President Corporate Affairs and Governance who, in this case, participates in the Committee meetings.

The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors lastly on June 4, 2020, available to the public at the Company’s website.

Sustainability and Scenarios Committee

Members: Karina A. Litvack (Chairman), Filippo Giansante, Emanuele Piccinno, Nathalie Tocci and Raphael Louis L.Vermeir.

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The Sustainability and Scenarios Committee is made up of non-executive Directors, a majority of whom are independent.

The Sustainability and Scenarios Committee provides recommendations and advice to the Board of Directors on scenarios and sustainability, 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: health, well-being and safety of people and communities; the respect and protection of rights, particularly of human rights; local development; access to energy, energy sustainability and climate change; environment and efficient use of resources; integrity and transparency; and innovation.

Board of Statutory Auditors

The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of May 13, 2020 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, 2022.

Name	Position	Year first appointed to Board of Statutory Auditors
Rosalba Casiraghi	Chairman	2017
Enrico Maria Bignami	Auditor	2017
Giovanna Ceribelli	Auditor	2020
Mario Notari (in office until September 1, 2020)	Auditor	2020
Roberto Maglio (in office from September 1, 2020)	Auditor	2020
Marco Seracini	Auditor	2014
Claudia Mezzabotta	Alternate	2017

Giovanna Ceribelli, Mario Notari, Marco Seracini and Roberto Maglio (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; Rosalba Casiraghi (Chairman), Enrico Maria Bignami and Claudia Mezzabotta (Alternate) were candidates listed in the slate presented by non-controlling shareholders.

On September 1, 2020, the Alternate Auditor Roberto Maglio, drawn from the list presented by the Ministry of Economy and Finance, replaced the Auditor Mario Notari following the latter’s resignation. Roberto Maglio will remain in office until the next Shareholders’ Meeting, which will appoint the Auditors necessary for the integration of the Board of Statutory Auditors.

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. In addition, 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”.

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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 andSEC 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;

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•

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 high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the 231 Supervisory Body. Moreover, as a result of changes in the Italian legislation governing the matter and in the Company’s organizational structure, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of June 4, 2020 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 Chairmanas 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.

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Court of Auditors (Corte dei conti)

The financial management of Eni is subject to the control of the Italian Court of Auditors in order to preserve the integrity of the public finances. This task has been carried out by the Magistrate of the Court of Auditors, Manuela Arrigucci, on the basis of the resolution approved in December 18-19, 2018, 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, 2020, Eni had a total of 31,495 employees, with a decrease of 558 employees, down by 1.7% compared to December 31, 2019, which mainly reflects an increase of 78 employees working in Italy and a decrease of 645 employees working abroad.

In 2020, Eni was confronted with the effects of the COVID-19 pandemic, which drove a collapse in hydrocarbons demand and put pressure on prices and margins. The contraction in economic activity and the decline in demand has determined the re-phasing of many projects abroad, resulting in the repatriation of many employees from abroad, which determined an increase in the workforce in Italy balanced by efficiency actions.

In addition we recorded the consolidation of the subsidiary D-SHARE and the acquisition of Evolvere a company engaged in the market of distributed generation from renewables in Italy.

Outside Italy the reduction of personnel headcount is mainly due to efficiency actions and the repatriation of employees to Italy.

Employees at year end

	2020		2019		2018
	(number)
Exploration & Production		9,815		10,272		10,448
Global Gas & LNG Portfolio		700		711		734
Refining & Marketing and Chemicals		11,471		11,626		11,457
Eni gas e luce, Power & Renewables		2,092		7,388		2,056
Corporate and Other activities		7,417		2,056		7,006
		31,495		32,053		31,701

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The table below sets forth Eni’s employees as of December 31, 2018, 2019 and 2020 in Italy and outside Italy:



		2020		2019		2018
		(number)
Exploration & Production	Italy		3,692		3,491		3,477
	Outside Italy		6,123		6,781		6,971
			9,815		10,272		10,448
Global Gas & LNG Portfolio	Italy		290		293		318
	Outside Italy		410		418		416
			700		711		734
Refining & Marketing and Chemicals	Italy		8,915		9,035		8,863
	Outside Italy		2,556		2,591		2,594
			11,471		11,626		11,457
Eni gas e luce, Power & Renewables	Italy		1,679		1,698		1,719
	Outside Italy		413		358		337
			2,092		2,056		2,056
Corporate and other activities	Italy		6,999		6,971		6,625
	Outside Italy		418		417		381
			7,417		7,388		7,006
Total	Italy		21,575		21,488		21,002
	Outside Italy		9,920		10,565		10,699
			31,495		32,053		31,701
of which senior managers			982		1,037		1,025

We seek to maintain constructive relationship with labor unions.

Share ownership

As of February 28, 2021, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 256,855 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		68,755
Board of Statutory Auditors
Marco Seracini	Auditor		2,000
Senior Managers			186,100(1)

(1)

Of which No. 20,000 shares owned by spouses not legally separated and by underage children.

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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 February 28, 2021, 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%16 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		4.37
Cassa Depositi e Prestiti SpA		936,179,478		25.96

Other Relevant Shareholders17 18

Number of shares owned

Percent of class

Norges Bank

51,386,189

1.42

As of February 28, 2021, the percentage of Eni’s treasury shares was equal to 0.92% of the share capital19. 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 10, 2021, there were 25,987,995 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 1.4% 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 on an arm’s length basis and in the interest of the Eni Group companies20.

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 of the Notes on Consolidated Financial Statements”.

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 note 20 — 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.

Major holdings pursuant to Article 120 of the Legislative Decree No. 58/1998 are updated also on the basis of communication made by intermediaries pursuant to Article 83-novies of the Legislative Decree No. 58/1998 in order to exercise the corporate rights.

Shareholders that have declared, pursuant to article 120 TUF, to own more than 1% of the share capital of the company in compliance with Consob resolutions No. 21326 of April 9, 2020, and No. 21434 of July 8, 2020 and No. 21672 of January 13, 2021.

UniCredit S.p.A. declared, pursuant to article 120 TUF, in compliance with Consob resolution No. 21434 of July 8, 2020 (i) to have exceeded on September 9, 2020 the threshold of ownership of 1% of the company’s capital and subsequently on September 11, 2020 the descent below this 1% threshold, (ii) to have exceeded on September 15, 2020 the above mentioned threshold of ownership and subsequently on September 17, 2020 the descent below this threshold and (iii) to have exceeded on September 18, 2020 the above mentioned threshold of ownership and subsequently on September 21, 2020 the descent below this threshold.

In the meeting of February 27, 2020, Eni’s Board of Directors resolved to submit to the Shareholder’s Meeting, to be held on May 13, 2020, the proposal of cancellation of the treasury shares acquired in 2019. Subsequently, following the cancellation of the treasury shares resolved by the Shareholders’ meeting of May 13, 2020, Eni holds n. 33,045,197 shares equal to 0.92% of the share capital.

For more details on internal rules on related parties transactions, please refer to Item 10, paragraph “Interests in Company’s transactions”.

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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 “Item 18 — Note 27 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 shareholders’ remuneration policy in line with our plans of underlying earnings and cash flow growth and considering the evolution in the oil price scenario.

In response to the crisis of the oil sector due to the COVID-19 pandemic which materially hit our earnings and cash flow in 2020, last July we defined a new distribution policy aimed at giving visibility and certainty to our shareholders in a period of great volatility.

Our remuneration policy was structured on two pillars: (i) a fixed dividend of €0.36 per share which payment is conditioned upon the price of the Brent crude oil reaching a minimum, pre-set threshold. The amount of this floor dividend will be revised going forward based on the Company delivering on its strategy and industrial targets; (ii) a variable component in the form of a progressive dividend which amounts depends on trends in the Brent price and of share buybacks which are set to start when the Brent price reaches certain levels. For 2021, the Company expects to make a full year forecast of the Brent price when approving the interim result at the end of July 2021 on which occasion it will decide the amount of cash returns to shareholders.

In February 2021, the Eni Board has revised the guidelines of this remuneration policy as follows:

•

the floor dividend is currently set at €0.36 per share conditional upon an average Brent price for the reference year of at least 43 $/bbl and will be upgraded going forward based on the Company’s delivering on its strategy and industrial targets;

•

in addition to the floor dividend, a variable dividend will be paid to shareholders as a portion of the incremental cash flow from operations in excess over capital expenditures, which we expect to earn due to oil prices rising above the threshold of 43 $/bbl. The ratio of such pay-out would grow reflecting any growth in oil price, from 30% up to 45% of the incremental cash flow generated at Brent prices above 43 $/bbl and up to 65 $/bbl;

•

a share buyback program is expected to start at a Brent price level of 56 $/bbl per barrel with a value of €300 million per year. This amount will rise to €400 million per year from 61 $/bbl of Brent and to €800 million per year from 66 $/bbl onward, as originally planned.

The Company’s dividend policy going forward and the sustainability of the dividends that the Company is planning to distribute over the next four years will depend upon a number of factors including hydrocarbons prices, achievement of the Company’s industrial targets, future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the oil price and exchange rate assumptions adopted by management and other planning and scenario assumptions described in “Item 5 — Management’s expectations of operations”. The parent company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. For further information on the Company’s dividend policy see “Item 5 — Management’s expectations of operations.”

At the General Shareholders’ Meeting scheduled for May 12, 2021, management intends to propose the distribution of a dividend of €0.36 per share for fiscal year 2020, of which €0.12 already paid as interim dividend in September 2020. Total cash outlay for the 2020 final dividend is expected at approximately €0.86 billion to be paid in 2021 (whereas €0.43 billion were distributed in September 2020) if the General Shareholders’ Meeting approves the annual dividend.

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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 Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, 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 10, 2021, there were 25,987,995 ADRs outstanding, representing 51,975,990 ordinary shares or approximately 1.4% of all Eni’s shares outstanding, held by 93 holders of record (including the Depository Trust Company) in the United States, 92 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 MTA and the Investment Vehicles Market (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 6.5%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective December 18, 2020.

A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, 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 MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective February 3, 2020: (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) ± 3.5% (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.

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Markets

Consob is the public authority responsible for regulating and supervising the Italian financial markets to, inter alia, ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, 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 mainresponsibilities 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, MTA (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 (“MiFID II”) and as implemented in Italy, (ii) Regulation (EU) No. 600/2014 (“MiFIR”), applicable from January 3, 2018, 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 from time to time, (“EMIR”) 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 available on the website of Consob or Bank of Italy.

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

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Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

Company register

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

The full text of Eni’s By-laws is attached as an exhibit to this Annual Report. On February 27, 2020 the Board approved an amendment to the By-laws regarding gender quotas in the composition of corporate bodies pursuant to Law no. 160 of 2019 and on May 13, 2020 the Shareholders’ Meeting approved an amendment to the By-laws regarding the cancellation of 28,590,482 treasury shares with no par value without changing the amount of the share capital of the Company. 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, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and in the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

Directors’ issues

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

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

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

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

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

For further information on Directors’ duties and responsibilities and, in particular, the role of the

Chairman see “Item 6 — Board of Directors’ duties and responsibilities”.

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Interests in Company’s transactions

As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob (“Commissione Nazionale per le Società e la Borsa” is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the “Consob Regulation”), the Board of Directors — on November 18, 2010 — unanimously approved the Management System Guidelines “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”21 (“MSG”), which has been in effect from January 1, 201122 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. This MSG and the subsequent amendments 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 MSG 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 MSG, Directors and Statutory Auditors issue a declaration, every six months 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.

On December 10, 2020 Consob issued Deliberation n. 21624 implementing the provisions set out in Legislative Decree No. 49/2019 that granted execution to European Directive n. 2017/828 that amended Directive 2007/36/EC as regards the encouragement of long-term shareholder engagement. Companies are required to align their procedures to the amended rules by June 30, 2021.

The amended rules must be applied starting from July 1, 2021. Eni will adapt its MSG within the terms established by law.

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 2020, see the Remuneration Report 2021 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.

The Board of Directors modified this Management System Guideline on January 19, 2012 and lastly on April 4, 2017.

This MSG 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 MSG, have been applied since December 1, 2010.

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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.

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 3,605, 594, 84824ordinary registered shares without indication of par value. 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 29, 2021, 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.

The Shareholders’ Meeting, held on May 13, 2020, has approved the proposal of cancellation of 28,590,482 treasury shares, without any impact on the Company’s share capital.

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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.

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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.

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”, the participation in the Shareholders’ Meeting of May 13, 2020 was permitted solely through the Shareholders’ representative designated by the Company pursuant to Article 135-undecies of Consolidated Law on Financial Intermediation. Decree Law no. 183/2020, ratified with amendments by Law no. 21/2021, extended the effectiveness of the above-mentioned measures also to the Shareholders’ Meeting to be held by July 31, 2021.

Stock ownership limitation and voting rights restrictions

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 325 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, 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; 5G technology; energy, transport and communications, as defined by the regulations which implement the relevant law.

With reference to the energy sector, the special powers, that have been expanded, on a temporary basis due to the COVID-19 pandemic, until June 30, 2021, include: a) veto power (or the power of imposing conditions or requirements) over certain transactions or resolutions involving strategic assets or companies that hold such assets ; and b) power of attaching conditions or opposing the acquisition by an entity outside of the EU of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets26.

This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below.

The temporary rules in force until June 30, 2021, introduced by art. 4-bis, paragraphs 3-bis and following of the law decree n. 105/2019, converted by law no. 133/2019, as most recently amended by law decree n. 137/2020, converted by law no. 176/2020, extends the obligation of notification to

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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.

With particular reference to the power referred to in letter b), until the notification and thereafter, up to the expiration of the term for the possible exercise of such power, the voting rights and any other non-financial right related to the significant shareholding may not be exercised.

In the case of non-fulfillment of imposed conditions, throughout the relevant period, the voting rights and any other non-financial right related to the significant shareholding may not be exercised. The resolutions adopted with the decisive vote of such shareholding, or otherwise the resolutions or acts adopted in breach or default of the imposed conditions are void. In addition, unless the fact constitutes a crime, failure to comply with imposed conditions 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.

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 Finance27 and the Consob Regulation28, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%29, 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 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.

purchases of controlling shares by foreign parties, including those based in the European Union, as well as to purchases of shares by non-EU parties, which transfer a share of voting rights or capital 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.

Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.

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. In the context of COVID-19 pandemic, Consob applied such power with resolutions No. 21326 of April 9, 2020, No. 21434 of July 8, 2020 and No. 21672 of January 13, 2021 that lowered, for a list of companies with extensive shareholding structure (including Eni), the thresholds triggering the disclosure obligation to Consob by investors, bringing them from 3% to 1%. This enhanced transparency regime is in force until April 13, 2021.

Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.

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For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria30. 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 investments31.

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 quoted 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 months32. 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.

Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.

Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.

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. In the context of Covid-19 emergency, Consob so decided with resolutions No. 21327 of April 9, 2020, No. 21434 of July 8, 2020 and No. 21672 of January 13, 2021.

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The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company.

Under the Consolidated Law on Finance, 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 Authority33 if the companies involved exceed given turnover thresholds. If the said merger, acquisition or change of control would create or strengthen a dominant position in the Italian market in a manner that eliminates or significantly reduces competition, 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 thresholds set by European or other countries’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value or market shares of the parties), the transaction can also be subject to the prior authorization by competition authorities of other jurisdictions.

Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than those required by law. Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.

Material contracts

None.

Exchange controls

Under current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by an Italian resident to a non-resident.

Taxation

The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.

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.

Autorità garante della concorrenza e del mercato (AGCM).

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Income tax

Dividends regarding income of financial year 2020 to be paid in 2021, received by Italian resident individuals, holding the shares or ADRs in connection with entrepreneurial activity, are included in the taxable income subject to personal income tax to the extent of 58.14% of their amount. Personal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends 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.

Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, 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.

Dividends paid to non-Italian residents are subject to the same 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.

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 companies and entities subject to a corporate income tax in a European Union Member State or in the European Economic Area.

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 90 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 shares 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 establishment 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.

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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 2019, are subject to substitute tax for 26%. For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the 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.

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.

However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, 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 convention 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).

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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. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, 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 which 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 the 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 the 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.

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The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the Italy U.S. Tax Treaty with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax.

Distributions

Subject to the passive foreign investment company (“PFIC”) rules discussed below, distributions paid on the Shares or ADSs will generally be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends-received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities.

For non-corporate U.S. Holders, dividends that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by Eni SpA that are received with respect to the ADSs will generally be qualified dividend income if the ADSs are readily tradable on an established securities market in the United States. Eni SpA’s ADSs are listed on the New York Stock Exchange and Eni SpA therefore expects that dividends with respect to the ADSs will be qualified dividend income. Dividends paid by Eni SpA with respect to the Shares will generally be qualified dividend income provided that, in the year that you receive the dividend, Eni SpA is eligible for the benefits of the Italy U.S. Tax Treaty. Eni SpA believes that it is currently eligible for the benefits of the Italy U.S. Tax Treaty and Eni SpA therefore expects that dividends on the Shares will also be qualified dividend income, but there can be no assurance that Eni SpA will continue to be eligible for the benefits of the Italy U.S. Tax Treaty.

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 distribution is includible in such person’s income, 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 U.S. Holder includes the dividend payment in income to the date he or she 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 income tax convention between the United States and Italy, 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.

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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 U.S. 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

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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.

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, Eni Finance USA 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, Eni Global Energy Markets (from January 1, 2021, formerly Eni Trading & Shipping) that are in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA, Eni Finance International and Eni Finance USA 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 instrument has been updated in light of the relevant changes in the main financial regulations (Mifid II/EMIR/Dodd Frank act). Eni’s activities are in compliance with regulatory requirements for 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, in 2013 the EMIR concepts of “risk reducing” and “non-risk reducing” derivatives were introduced. Company’s activities in financial instruments were thus classified in order to clearly: a) isolate ex ante non-risk reducing activities; b) define a priori the types of OTC derivative contracts included in the hedging portfolios and the eligibility criteria, and stating that the transactions in contracts included in the hedging portfolios are limited to covering risks directly related to commercial or treasury financing activities; and c) provide for a sufficiently disaggregate view of the hedging portfolios in terms of for example asset class, product and time horizon, in order to establish the direct link between the portfolio of hedging transactions and the risks that this portfolio seeks to hedge. A financial instrument can be qualified as risk reducing when, by itself or in combination with other derivative contracts (so-called macro or portfolio hedging) it:

(i)

directly or through closely correlated instruments (so-called proxy hedging) covers the risks arising from potential changes in the value of different assets under Eni control or that Eni will have under its controls 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 hedging contract 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 to 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 or an order received by mean of an internal derivative, 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, in accordance to a portfolio basis. A central department processes a continuous flow of orders from the Group 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

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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 accounted to 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 to 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 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, prices 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 to such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the portfolio in line with company’s targets. Market risk associated to 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

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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 27 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 agent for the Eni SpA 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	Up to U.S. $5.00 per 100 ADSs	Person to whom the distribution

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Service		Rate	By Whom Paid
	or other cash distributions (e.g., upon a sale of rights and other entitlements).	(or fraction thereof) held.	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 2020, the Depositary reimbursed to Eni $1,800,000 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

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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.

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.

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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, 2020.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2020, has been audited by PricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 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. Board of 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, Giovanna Ceribelli, Roberto Maglio and Marco Seracini. All members are independent.

Item 16B. Code of Ethics

Eni adopted a Code of Ethics that applies to all Eni’s employees, including Chiefs, 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 the 2019 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) has served as Eni principal independent public auditor for fiscal year 2020 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.

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The following table shows total fees for services rendered to Eni by its public auditors PwC SpA and member firms of its network for the years ended December 31, 2020 and 2019.

	Year ended December 31,
	2020		2019
	(€ thousand)
Audit fees		19,605		15,748
Audit-related fees		1,412		1,045
Tax fees
All other fees
Total		21,017		16,793

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 audits of pension and benefit plans, merger and acquisition due diligence, audit, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards.

Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning.

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 pre-approved. Such policy is applied to entities controlled (directly or indirectly) by Eni SpA as well as to jointly controlled entities that are material to the Eni Group. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors.

During 2020, 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).

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Item 16E. Purchases of equity securities by the issuer and affiliated purchasers

In the course of the year 2020 and up to the date of this report, none of the Company or its affiliated purchasers have executed any purchase of equity securities of the issuer since the end of 2019 and up to and as of the date of the 20-F filing for the year ended December 31, 2020.

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 New York 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 2018 for Italian listed companies, which Eni has adopted.

On December 23, 2020, Eni’s Board of Directors decided to adopt the new Code approved by the Italian Corporate Governance Committee in January 2020 effective from January 1, 2021.

Independent Directors

NYSE standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off “ period following the termination of any relationship that compromised a Director’s independence.

Eni standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies 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 2018 provides for additional independence requirements, recommending that the Board of Directors includes an adequate number of independent non-executive Directors. In particular, for issuers belonging to FTSE-MIB index of the Italian Stock Market, like Eni, the Corporate Governance Code 2018 recommends that at least one-third of the members of the Board of Directors shall be independent Directors. In any event, independent Directors shall not be fewer than two. According to new Code, in large companies other than those with concentrated ownership, like Eni, independent directors should account for at least half of the board (this recommendation shall

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apply starting from the first renewal of the board of directors following December 31, 2020). Independence is defined as not being currently or recently involved in any direct or indirect relationship with the issuer or other parties associated with the issuer and that may influence his/her independent judgment. After the appointment of a Director who qualifies as independent and subsequently, upon the occurrence of circumstances affecting the independence requirements 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 the result of its evaluations, after the appointment, through a press release to the market and, subsequently, 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 2018 and the new Code, independent Directors shall meet at least once a year without the other Directors.

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 Corporate Governance Code 2018 and the new 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 Corporate Governance Code 2018. On May 14, 2020, the Board of Directors of Eni established the Nomination Committee, chaired by Ada Lucia De Cesaris (independent Director) and composed of Pietro Guindani (independent Director) and Emanuele Piccinno (non-executive Director independent pursuant to law). 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

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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 2018, 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. Pursuant to the Code, the remuneration committee is made up of non-executive directors, the majority of whom are independent, and is chaired by an independent director. At least one of the Committee’s members shall have an adequate understanding of and experience in financial matters or compensation policies. First established by the Board of Directors in 1996, the Remuneration Committee is currently chaired by Director Nathalie Tocci . The other members include Directors Karina A. Litvack, and Raphael Louis L. Vermeir. 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 meetings of March 18, 2020 and June 4, 2020, 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.

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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, 2020 and 2019, and the related consolidated profit and loss accounts and consolidated statements of comprehensive income, changes in shareholders’ equity and cash flows for each of the two years in the period ended December 31, 2020, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020 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, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the COSO.

Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

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.

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

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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 Proved Oil and Natural Gas Reserves on Property, Plant and Equipment, Net

As described in Notes 1, 11 and 14 to the consolidated financial statements, the Company’s consolidated net carrying amount for property, plant and equipment was €53.9 billion as of December 31, 2020, of which a significant portion relates to Exploration and Production (E&P) for €48.1 billion. The Company’s depreciation, depletion and amortization (DD&A) expense for E&P wells, plant and machinery was €5.6 billion for the year ended December 31, 2020. 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 exploration rights and acquired proved mineral interests are amortized over proved reserves, and proved exploration and appraisal costs and development expenditures are depreciated over proved developed 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 judgement; (ii) projections regarding future rates of production and operating costs as well as the timing and amounts of development expenditures; (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 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. The estimates of oil and natural gas reserves have been developed by the Company’s internal petroleum engineers and independent petroleum engineers (collectively “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of 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 specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of oil and natural gas reserve volumes and the assumptions applied to the data related to the future development costs and operating costs.

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procedures also included, among others, testing the completeness and accuracy of the data related to future development costs and operating costs. Additionally, these procedures included evaluating whether the assumptions applied to the data related to future development costs and operating costs were reasonable considering the past performance of the Company.

Impairment Assessment of Certain Proved Oil and Natural Gas Properties

As described in Notes 1, 11 and 14 to the consolidated financial statements, the Company’s consolidated net carrying amount for property, plant and equipment was €53.9 billion as of December 31, 2020, of which a significant portion relates to Exploration and Production (E&P) for €48.1 billion. The Company incurred impairment losses before taxes associated with the proved oil and natural gas properties in the E&P segment of €1.9 billion for the year ended December 31, 2020. Non-financial 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 (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 principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed; when appropriate according to facts and circumstances, management’s estimate could also include risk-adjusted unproved reserves. The estimate of the future amount of production is based on assumptions related to future commodity prices, lifting and development costs, field decline rates, market demand and other factors.

The principal considerations for our determination that performing procedures relating to the impairment assessment of certain 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; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions, including future production volumes, commodity prices and development costs as well as operating 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 proved oil and natural gas properties impairment assessment. 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 production volumes, commodity prices and development costs as well as operating costs. Evaluating the reasonableness of management’s assumptions related to future commodity prices involved comparing the prices against observable market data. Evaluating future development costs as well as operating costs involved evaluating the reasonableness of the 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. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Property, Plant and Equipment, Net” and the reasonableness of the future production volumes. As a basis for using this work, we obtained an understanding of the specialists’ qualifications and assessed the Company’s relationship with the specialists. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.

PricewaterhouseCoopers SpA (signed)
Rome, Italy
April 2, 2021

We have served as the Company’s auditor since 2019.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of
Eni S.p.A.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Eni S.p.A. (the “Company”) as of December 31, 2018, the related consolidated profit and loss accounts and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018, and the results of its operations and its cash flows for the period ended December 31, 2018, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Revision of Segment Reporting

As discussed in Note 35 to the Consolidated Financial Statements, the Company revised its segment reporting. The revision has been retrospectively adjusted for the year ended December 31, 2018.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ EY S.p.A.

We served as the Company’s auditor from 2010 to 2018.

Rome, Italy
April 5, 2019
Except for revisions to segment reporting in Note 35, as to which the date is
April 2, 2021.

Note that the report set out above is included for the purposes of Eni S.p.A.’s Annual Report on Form 20-F for 2020 only and does not form part of Eni S.p.A.’s Annual Report for 2018.

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CONSOLIDATED BALANCE SHEET
(€ million)

		December 31, 2020				December 31, 2019
	Note	Total amount		of which with related parties		Total amount		of which with related parties
ASSETS
Current assets
Cash and cash equivalents	(5)		9,413				5,994
Financial assets held for trading	(6)		5,502				6,760
Other current financial assets	(16)		254		41		384		60
Trade and other receivables	(7)		10,926		802		12,873		704
Inventories	(8)		3,893				4,734
Income tax receivables	(9)		184				192
Other current assets	(10) (23)		2,686		145		3,972		219
			32,858				34,909
Non-current assets
Property, plant and equipment	(11)		53,943				62,192
Right-of-use assets	(12)		4,643				5,349
Intangible assets	(13)		2,936				3,059
Inventory – Compulsory stock	(8)		995				1,371
Equity-accounted investments	(15)		6,749				9,035
Other investments	(15)		957				929
Other non-current financial assets	(16)		1,008		766		1,174		911
Deferred tax assets	(22)		4,109				4,360
Income tax receivables	(9)		153				173
Other non-current assets	(10) (23)		1,253		74		871		181
			76,746				88,513
Assets held for sale	(24)		44				18
TOTAL ASSETS			109,648				123,440
LIABILITIES AND EQUITY
Current liabilities
Short-term debt	(18)		2,882		52		2,452		46
Current portion of long-term debt	(18)		1,909				3,156
Current portion of long-term lease liabilities	(12)		849		54		889		5
Trade and other payables	(17)		12,936		2,100		15,545		2,663
Income tax payables	(9)		243				456
Other current liabilities	(10) (23)		4,872		452		7,146		155
			23,691				29,644
Non-current liabilities
Long-term debt	(18)		21,895				18,910
Long-term lease liabilities	(12)		4,169		112		4,759		8
Provisions	(20)		13,438				14,106
Provisions for employee benefits	(21)		1,201				1,136
Deferred tax liabilities	(22)		5,524				4,920
Income tax payables	(9)		360				454
Other non-current liabilities	(10) (23)		1,877		23		1,611		23
			48,464				45,896
Liabilities directly associated with assets held for sale	(24)
TOTAL LIABILITIES			72,155				75,540
Share capital			4,005				4,005
Retained earnings			34,043				35,894
Cumulative currency translation differences			3,895				7,209
Other reserves and equity instruments			4,688				1,564
Treasury shares			(581)				(981)
Profit (loss)			(8,635)				148
Equity attributable to equity holders of Eni			37,415				47,839
Non-controlling interest			78				61
TOTAL EQUITY	(25)		37,493				47,900
TOTAL LIABILITIES AND EQUITY			109,648				123,440

See the accompanying notes.

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(€ million except as otherwise stated)


		2020				2019				2018
	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			43,987		1,164		69,881		1,248		75,822		1,383
Other income and revenues			960		35		1,160		4		1,116		8
REVENUES AND OTHER INCOME	(28)		44,947				71,041				76,938
Purchases, services and other	(29)		(33,551)		(6,595)		(50,874)		(9,173)		(55,622)		(8,009)
Net (impairment losses) reversals of trade and other receivables	(7)		(226)		(6)		(432)		28		(415)		26
Payroll and related costs	(29)		(2,863)		(36)		(2,996)		(28)		(3,093)		(22)
Other operating income (expense)	(23)		(766)		13		287		19		129		319
Depreciation and amortization	(11) (12) (13)		(7,304)				(8,106)				(6,988)
Net (impairment losses) reversals of tangible and intangible assets and right-of-use assets	(14)		(3,183)				(2,188)				(866)
Write-off of tangible and intangible assets	(11) (13)		(329)				(300)				(100)
OPERATING PROFIT (LOSS)			(3,275)				6,432				9,983
Finance income	(30)		3,531		114		3,087		96		3,967		115
Finance expense	(30)		(4,958)		(26)		(4,079)		(36)		(4,663)		(283)
Net finance income (expense) from financial assets held for trading	(30)		31				127				32
Derivative financial instruments	(23) (30)		351				(14)				(307)
FINANCE INCOME (EXPENSE)			(1,045)				(879)				(971)
Share of profit (loss) from equity-accounted investments			(1,733)				(88)				(68)
Other gain (loss) from investments			75				281				1,163
INCOME (EXPENSE) FROM INVESTMENTS	(15) (31)		(1,658)				193				1,095
PROFIT (LOSS) BEFORE INCOME TAXES			(5,978)				5,746				10,107
Income taxes	(32)		(2,650)				(5,591)				(5,970)
PROFIT (LOSS)			(8,628)				155				4,137
Attributable to Eni			(8,635)				148				4,126
Attributable to non-controlling interest			7				7				11
Earnings (loss) per share (€ per share)	(33)
Basic			(2.42)				0.04				1.15
Diluted			(2.42)				0.04				1.15

See the accompanying notes.

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CONSOLIDATED STATEMENTS 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		Net profit for the year		Total		Non- controlling interest		Total equity
Balance at December 31, 2019	(25)		4,005		35,894		7,209		1,564		(981)		148		47,839		61		47,900
Profit (loss) for the year													(8,635)		(8,635)		7		(8,628)
Other items of comprehensive income (loss)
Remeasurements of defined benefit plans net of tax effect	(25)								9						9				9
Change of minor investments measured at fair value with effects to OCI	(25)								24						24				24
Items that are not reclassified to profit or loss in later periods									33						33				33
Currency translation differences	(25)						(3,313)		(1)						(3,314)				(3,314)
Change in the fair value of cash flow hedge derivatives net of tax effect	(25)								469						469				469
Share of “Other comprehensive income (loss)” on equity-accounted investments	(25)								32						32				32
Items that may be reclassified to profit or loss in later periods							(3,313)		500						(2,813)				(2,813)
Total comprehensive income (loss) of the year							(3,313)		533				(8,635)		(11,415)		7		(11,408)
Dividend distribution of Eni SpA	(25)				1,542								(3,078)		(1,536)				(1,536)
Interim dividend distribution of Eni SpA	(25)				(429)										(429)				(429)
Dividend distribution of other companies																	(3)		(3)
Allocation of 2019 net income					(2,930)								2,930
Cancellation of treasury shares	(25)								(400)		400
Increase in non controlling interest relating to acquisition of consolidated entities	(26)																15		15
Issue of perpetual subordinated bonds	(25)								3,000						3,000				3,000
Transactions with holders of equity instruments					(1,817)				2,600		400		(148)		1,035		12		1,047
Costs for the issue of perpetual subordinated bonds					(25)										(25)				(25)
Other changes					(9)		(1)		(9)						(19)		(2)		(21)
Other changes in equity					(34)		(1)		(9)						(44)		(2)		(46)
Balance at December 31, 2020	(25)		4,005		34,043		3,895		4,688		(581)		(8,635)		37,415		78		37,493

See the accompanying notes.

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (continued)
(€ million)

		Equity attributable to equity holders of Eni
	Note	Share capital		Retained earnings		Cumulative currency translation differences		Other reserves		Treasury shares		Net profit for the year		Total		Non- controlling interest		Total shareholders’ equity
Balance at December 31, 2018			4,005		35,189		6,605		1,672		(581)		4,126		51,016		57		51,073
Changes in accounting policies (IAS 28)					(4)										(4)				(4)
Balance at January 1, 2019			4,005		35,185		6,605		1,672		(581)		4,126		51,012		57		51,069
Profit (loss) for the year													148		148		7		155
Other items of comprehensive income (loss)
Remeasurements of defined benefit plans net of tax effect	(25)								(37)						(37)				(37)
Share of “Other comprehensive income (loss)” on equity-accounted investments	(25)								(7)						(7)				(7)
Change of minor investments measured at fair value with effects to OCI	(25)								(3)						(3)				(3)
Items that are not reclassified to profit or loss in later periods									(47)						(47)				(47)
Currency translation differences	(25)						604								604				604
Change in the fair value of cash flow hedge derivatives net of tax effect	(25)								(482)						(482)				(482)
Share of “Other comprehensive income (loss)” on equity-accounted investments	(25)								(6)						(6)				(6)
Items that may be reclassified to profit or loss in later periods							604		(488)						116				116
Total comprehensive income (loss) of the year							604		(535)				148		217		7		224
Dividend distribution of Eni SpA	(25)				1,513								(2,989)		(1,476)				(1,476)
Interim dividend distribution of Eni SpA	(25)				(1,542)										(1,542)				(1,542)
Dividend distribution of other companies																	(4)		(4)
Reimbursements to minority shareholders																	(1)		(1)
Allocation of 2018 net income					1,137								(1,137)
Acquisition of treasury shares	(25)				(400)				400		(400)				(400)				(400)
Transactions with shareholders					708				400		(400)		(4,126)		(3,418)		(5)		(3,423)
Other changes in shareholders’ equity					1				27						28		2		30
Balance at December 31, 2019	(25)		4,005		35,894		7,209		1,564		(981)		148		47,839		61		47,900

See the accompanying notes.

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (continued)
(€ million)

	Equity attributable to equity holders of Eni
	Share capital		Retained earnings		Cumulative currency translation differences		Other reserves		Treasury shares		Net profit for the year		Total		Non- controlling interest		Total shareholders’ equity
Balance at December 31, 2017		4,005		34,525		4,818		1,889		(581)		3,374		48,030		49		48,079
Changes in accounting policies (IFRS 9 and 15)				245										245				245
Balance at January 1, 2018		4,005		34,770		4,818		1,889		(581)		3,374		48,275		49		48,324
Profit (loss) for the year												4,126		4,126		11		4,137
Other items of comprehensive income (loss)
Remeasurements of defined benefit plans net of tax effect								(17)						(17)				(17)
Change of minor investments measured at fair value with effects to OCI								15						15				15
Items that are not reclassified to profit or loss in later periods								(2)						(2)				(2)
Currency translation differences						1,787								1,787				1,787
Change in the fair value of cash flow hedge derivatives net of tax effect								(185)						(185)				(185)
Share of “Other comprehensive income (loss)” on equity-accounted investments								(24)						(24)				(24)
Items that may be reclassified to profit or loss in later periods						1,787		(209)						1,578				1,578
Total comprehensive income (loss) of the year						1,787		(211)				4,126		5,702		11		5,713
Dividend distribution of Eni SpA				1,441								(2,881)		(1,440)				(1,440)
Interim dividend distribution of Eni SpA				(1,513)										(1,513)				(1,513)
Dividend distribution of other companies																(3)		(3)
Allocation of 2017 net income				493								(493)
Transactions with shareholders				421								(3,374)		(2,953)		(3)		(2,956)
Other changes in shareholders’ equity				(2)				(6)						(8)				(8)
Balance at December 31, 2018		4,005		35,189		6,605		1,672		(581)		4,126		51,016		57		51,073

See the accompanying notes.

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CONSOLIDATED STATEMENT OF CASH FLOWS
(€ million)


	Note	2020			2019			2018
Profit (loss)				(8,628)			155			4,137
Adjustments to reconcile profit (loss) to net cash provided by operating activities
Depreciation and amortization	(11) (12) (13)			7,304			8,106			6,988
Net Impairments (reversals) of tangible and intangible assets and right-of-use assets	(14)			3,183			2,188			866
Write-off of tangible and intangible assets	(11) (13)			329			300			100
Share of (profit) loss of equity-accounted investments	(15) (31)			1,733			88			68
Net gain on disposal of assets				(9)			(170)			(474)
Dividend income	(31)			(150)			(247)			(231)
Interest income				(126)			(147)			(185)
Interest expense				877			1,027			614
Income taxes	(32)			2,650			5,591			5,970
Other changes				92			(179)			(474)
Cash flow from changes in working capital				(18)			366			1,632
- inventories			1,054			(200)			15
- trade receivables			1,316			1,023			334
- trade payables			(1,614)			(940)			642
- provisions			(1,056)			272			(238)
- other assets and liabilities			282			211			879
Net change in the provisions for employee benefits							(23)			109
Dividends received				509			1,346			275
Interest received				53			88			87
Interest paid				(928)			(1,029)			(609)
Income taxes paid, net of tax receivables received				(2,049)			(5,068)			(5,226)
Net cash provided by operating activities				4,822			12,392			13,647
- of which with related parties	(36)			(4,640)			(6,356)			(2,707)
Cash flow from investing activities				(5,959)			(11,928)			(9,321)
- tangible assets	(11)			(4,407)			(8,049)			(8,778)
- prepaid right-of-use assets	(12)						(16)
- intangible assets	(13)			(237)			(311)			(341)
- consolidated subsidiaries and businesses net of cash and cash equivalent acquired	(26)			(109)			(5)			(119)
- investments	(15)			(283)			(3,003)			(125)
- securities and financing receivables held for operating purposes				(166)			(237)			(366)
- change in payables in relation to investing activities				(757)			(307)			408

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CONSOLIDATED STATEMENT OF CASH FLOWS (continued)
(€ million)


	Note	2020		2019		2018
Cash flow from disposals			216		794		2,142
- tangible assets			12		264		1,089
- intangible assets					17		5
- consolidated subsidiaries and businesses net of cash and cash equivalent disposed of	(26)				187		(47)
- tax on disposals					(3)
- investments			16		39		195
- securities and financing receivables held for operating purposes			136		195		294
- change in receivables in relation to disposals			52		95		606
Net change in securities and financing receivables held for non-operating purposes			1,156		(279)		(357)
Net cash used in investing activities			(4,587)		(11,413)		(7,536)
- of which with related parties	(36)		(1,372)		(2,912)		(3,314)
Increase in long-term financial debt	(18)		5,278		1,811		3,790
Repayments of long-term financial debt	(18)		(3,100)		(3,512)		(2,757)
Payments of lease liabilities	(12)		(869)		(877)
Increase (decrease) in short-term financial debt	(18)		937		161		(713)
Dividends paid to Eni’s shareholders			(1,965)		(3,018)		(2,954)
Dividends paid to non-controlling interest			(3)		(4)		(3)
Reimbursements to non-controlling interest					(1)
Acquisition of additional interests in consolidated subsidiaries					(1)
Acquisition of treasury shares					(400)
Issue of perpetual subordinated bonds	(25)		2,975
Net cash used in financing activities			3,253		(5,841)		(2,637)
- of which with related parties	(36)		164		(817)		16
Effect of exchange rate changes and other changes on cash and cash equivalents			(69)		1		18
Net increase (decrease) in cash and cash equivalents			3,419		(4,861)		3,492
Cash and cash equivalents – beginning of the year	(5)		5,994		10,855		7,363
Cash and cash equivalents – end of the year	(5)		9,413		5,994		10,855

See the accompanying notes.

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Notes on Consolidated Financial Statements

Impact of COVID-19 pandemic

The trading environment in 2020 saw a material reduction in the global demand for crude oil driven by the lockdown measures implemented worldwide to contain the spread of the COVID-19 pandemic causing a sharp contraction in economic activity, international commerce and travel, mainly during the peak of the crisis in the first and second quarter of 2020.

The shock in the hydrocarbon demand occurred against the backdrop of a structurally oversupplied oil market, as highlighted by the disagreements among OPEC+ members on the response to be adopted to manage the crisis in early March 2020. The producing countries of the cartel decided against maintaining the existing quotas and as a result the market was inundated with production while demand was crumbling. Those developments led to a collapse in commodity prices.

At the peak of the downturn, between March and April, the Brent marker price fell to about 15 $/barrel, the lowest level in over twenty years. The oversupply drove oil markets into contango, a situation when prices per prompt delivery quote below prices for future deliveries, while both land and floating storages reached the highest technical filling levels.

Since May, oil prices have been staging a turnaround thanks to an agreement reached within OPEC+ which implemented production cuts and an ongoing recovery in the world economy and oil consumption following an ease to restrictive measures, which were driven in large part by a strong rebound of activity in China. Brent prices recovered to almost 45 $/barrel in the summer months.

However, during the autumn months the macroeconomic rebound hit a standstill in the USA and in Europe due to a continuous recrudescence in virus cases, which forced the governments and local authorities in those countries to reinstate partial or full lockdowns and other restrictive measures that weighted heavily on oil and products demands as millions of people continued living stranded.

In this period, crude oil prices were supported by strict production discipline on part of OPEC+ members and the market was able to accommodate the return of Libya’s production by the end of September.

Barometer of the weakness of the fundamentals in the energy sector in the third quarter was the trend in the refining margins which dropped into negative territory due to weak demand for fuels and the crisis in the airline sector, which prevented refiners from passing the cost of the crude oil feedstock to the final prices of products. To make things worse, OPEC+ production cuts impacted the availability of medium-heavy crudes, narrowing the price differentials with light-medium qualities like the Brent crude and squeezing the refiners’ conversion advantage.

However, since mid-November a few market and macroeconomic developments triggered a rally in oil prices, which reached 50 $/bbl at the end of the year rebounding from the still depressed level of October and then rose to an average of over 60 $/barrel in the first quarter of 2021.

In 2020 due to the macroeconomic and market developments caused by the COVID-19 pandemic, the price of the Brent benchmark crude oil prices decreased by 35% compared to the previous year, with an annual average of 42 $/barrel, the price of natural gas at the Italian spot market “PSV” declined on average by 35%, and the Standard Eni Refining Margin – SERM decreased by 60%.

Considering the market trends, management revised the Company’s outlook for hydrocarbons prices assuming a more conservative oil scenario with a Long Term Brent price at 60 $/barrel in 2023 real terms (compared to the previous projection of 70 $/barrel) to reflect the possible structural effects of the pandemic on oil demand and the risk that the energy transition will accelerate due to the fiscal policies adopted by governments to rebuild the economy on more sustainable basis. These developments had negative, material effects on Eni’s results of operations and cash flow.

In 2020, Eni reported a net loss of €8.6 billion due to the reduction in revenues driven by lower realized prices and margins for hydrocarbons with an estimated impact of €6.8 billion and lower production volumes and other business impacts caused by the COVID-19 pandemic for €1 billion, as well as the recognition of impairment losses of €3.2 billion taken at oil&gas assets and refineries due to a revised management’s outlook on long-term oil and gas prices and lowered assumptions for the refining margins. A loss of approximately €1.3 billion was incurred in relation to the evaluation of inventories of oil and products, which were aligned to their net realizable values at period end, and a €1.7 billion loss taken at equity-accounted investments. All these trends caused the Group to incur an operating loss of €3.3 billion.

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These effects were partially offset by cost efficiencies and other management initiatives to counter the effects of the pandemic. Furthermore, the Group net loss for the year was also affected for €1.3 billion by the write-down of deferred tax assets.

Net cash provided by operating activities declined to €4.8 billion with a reduction of 61% compared to 2019, due to lower prices of hydrocarbons and other scenario effects for €6 billion and the negative impact on operations associated with the COVID-19 for €1.3 billion attributable to reduced expenditures, lower demand for fuel and chemicals, longer maintenance standstills in response to the COVID-19 emergency, lower LNG offtakes and lower gas demand and higher provisions for impairment losses at trade receivables.

These negative impacts were partially offset by cost savings and other initiatives in response to the pandemic crisis.

In order to respond to this large-scale shortfall, management has taken several decisive actions to preserve the Company’s liquidity, the ability to cover maturing financial obligations and to mitigate the impact of the crisis on the Group’s net financial position, as follows:

•

In 2020 Eni reduced capital expenditures by a significant amount. Those capex reductions mainly related to upstream activities, targeting production optimization activities and the rephasing of certain development projects. The delayed or re-phased activities can be restarted quickly in normal conditions, determining a recovery of related production.

•

Implemented widespread cost reduction initiatives across all businesses resulting in significant cost savings.

•

In May 2020, a €2 billion bond was issued. Then, in October two hybrid bonds were issued for a total amount of €3 billion; those latter bonds are classified among equity for balance sheet purposes.

•

A share repurchase program approved before the start of the crisis was put on hold.

•

Established a new dividend policy with the introduction of a variable component of the dividend in line with the volatility of the scenario. The new policy establishes a floor dividend currently set at 0.36 €/share under the assumption of a Brent scenario of at least 43 $/barrel and a growing variable component based on a recovery in the crude oil scenario. The floor amount will be revalued over time depending on the Company delivering on its industrial targets. For 2020, the dividend proposal is equal to the floor dividend.

The Company limited the increase in net borrowings before IFRS 16 which closed the year at €11.6 billion (unchanged over 2019), while retaining leverage at 0.31. The Company can count to fulfill the financial obligations coming due in the next future on a liquidity reserve of €20.4 billion as of December 31, 2020, consisting of:

•

cash and cash equivalents of €9.4 billion;

•

€5.3 billion of undrawn committed borrowing facilities;

•

€5.5 billion of readily disposable securities (mainly government bonds and corporate investment grade bond) and €0.2 billion of short-term financing receivables.

This reserve is considered adequate to cover the main financial obligations maturing in the next twelve months relating to:

•

short-term debt of €2.9 billion;

•

maturing bonds of €1.1 billion and other maturing long-term debt of €1.1 billion

•

committed investments of €4.3 billion;

•

instalments of leasing contracts coming due of €1.1 billion

•

the payment of a floor dividend for approximately €1.5 billion (including the final 2020 dividend and the interim floor dividend for 2021 due to paid in September).

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1 Significant accounting policies, estimates and judgements

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 concern1 basis in accordance with International Financial Reporting Standards (IFRS)2 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 2020 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on April 1, 2021, were audited by the external auditor PricewaterhouseCoopers SpA. The external auditor of Eni SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other external auditors, PricewaterhouseCoopers SpA takes the responsibility of their work.

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 judgements 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 judgements relevant for the preparation of the Consolidated Financial Statement are described below.

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. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee, i.e. the activities that significantly affect the investee’s returns.

Subsidiaries are consolidated, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases.

With reference to the impacts of COVID-19, see information provided in the previous paragraph.

IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).

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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.

The Consolidated Financial Statements do not consolidate: (i) some subsidiaries being immaterial, either individually or in the aggregate; (ii) companies whose consolidation does not produce material impacts, that are 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. The abovementioned exclusions do not produce material3 impacts on the Consolidated Financial Statements4.

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. 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; and (iii) any amount related to the former subsidiary previously recognised in other comprehensive income which may be reclassified subsequently to the profit and loss account5. 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.

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 revenue/expenses of joint operations on the basis of its rights and obligations relating to the arrangements.

After the initial recognition, the assets/liabilities and revenue/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 net of any impairment losses.

Investments in associates

An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

According to IFRSs, information is material if omitting, misstating or obscuringit could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements.

Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”.

Conversely, 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.

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Consolidated companies’ financial statements are audited by external auditors who also audit the information required for the preparation of the Consolidated Financial Statements.

The equity method of accounting

Investments in joint ventures, associates and immaterial unconsolidated subsidiaries, are accounted for using the equity method.6

Under the equity method, investments are initially recognised at cost, 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 date of initial recognition, to reflect new information obtained about facts and circumstances that existed at the date of initial recognition. Subsequently, 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.

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 when incurred.

Joint ventures, associates and immaterial unconsolidated subsidiaries are accounted for at cost less any accumulated impairment losses, if this does not result in a misrepresentation of the Company’s financial position and performance.

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.

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.

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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).10 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.11

Significant accounting estimates and judgements: 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 the management makes complex judgements 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 business combinations, 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 eliminated.

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. In both cases, unrealised losses are not eliminated unless 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, 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.

Fair value measurement principles are described in the accounting policy for “Fair value measurements”.

As an alternative, IFRSs allow to use the full goodwill method, which leads to the portion of goodwill/badwill attributable to non-controlling interests being recognised; the choice of measurement basis for goodwill/badwill (partial goodwill method vs. full goodwill method) is made on a transaction-by-transaction basis.

If 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.

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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.

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 2020		Exchange rate at December 31, 2020		Annual average exchange rate 2019		Exchange rate at December 31, 2019		Annual average exchange rate 2018		Exchange rate at December 31, 2018
U.S. Dollar		1.14		1.23		1.12		1.12		1.18		1.15
Pound Sterling		0.89		0.90		0.88		0.85		0.88		0.89
Australian Dollar		1.66		1.59		1.61		1.60		1.58		1.62

Significant accounting policies

The most significant 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”).

When 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”.

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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 expenditure

Development expenditure, 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 expenditure 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

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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. 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. A similar scheme applies to service contracts.

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 judgements: 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 judgement; (ii) projections regarding future rates of production and operating costs as well as timing and amount of development expenditures; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) 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 (v) changes in oil and natural gas prices which could affect expected future cash flows and 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 or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.

Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves. Similar uncertainties concern unproved reserves.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditures required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such 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.

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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 and impairment charges. 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 recognised using the cost model and stated at their purchase price or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management. 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.

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 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 recognised in the profit and loss account.

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Leases13 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.

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 depend 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

The accounting policies related to leases have been defined on the basis of IFRS 16 “Leases” effective from January 1, 2019. As allowed by the accounting standard, the new requirements have been applied without restating the comparative years. The previous accounting policies about leases required essentially that: (i) assets held under finance lease, or under arrangements that did not take the legal form of a finance lease but substantially transferred all the risks and rewards incidental to ownership of the leased asset, were recognised, at the commencement of the lease, at their fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments, within property, plant and equipment as a contra account to a financing payable to the lessor; and (ii) lease payments under an operating lease were recognised as an expense over the lease term.

As 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.

The 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.

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.

Eni, 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.

Conversely, 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.

Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained.

Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the right-of-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.

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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.

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, 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 judgements: lease transactions

With reference to lease contracts, management makes significant estimates and judgements related to: (i) determining the lease term, making assumptions about the exercise of 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 used for tangible assets and they are not revalued for financial reporting purposes.

Intangible assets with finite useful lives are amortised on a systematic basis over their useful life; the amount to be amortised and the recoverability of the carrying amount are determined 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 the goodwill and other intangible assets see the accounting policy “Impairment of non-financial assets”.

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Costs of obtaining a contract with a customer are recognised on the balance sheet if the Company expects to recover those costs. 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 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 resulting 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.

Cash-generating units may include corporate assets which do not generate cash inflows independently of other assets or group of assets, allocable on a reasonable and consistent basis. Corporate assets not attributable to a single cash-generating unit are allocated to a group of cash-generating units. 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 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 cash-generating unit, 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 and is based on management’s planning assumptions, in the short and medium term, takes into account the projections of market analysts and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace.

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.

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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 segment, the related discounted cash outflows are treated as a reduction of the headroom of that specific 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) segment, the Chemical business and each business within the Eni gas e luce, Power & Renewables segment, taking into account their different risk compared to Eni as a whole, specific WACC rates have been defined on the basis of a sample of comparable companies, adjusted to take into account the specific country-risk premium. For the other segments/businesses, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate derived, through an iteration process, from a post-tax valuation.

When the carrying amount of the CGU, including goodwill allocated thereto, determined taking into account any impairment loss of the non-current assets belonging to the CGU, exceeds its recoverable amount, the excess is 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 recoverable amount of assets with finite useful lives.

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 recognised 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 Chemical business is determined by applying the weighted average cost on an annual basis.

For the recognition criteria of forestry certificates see the accounting policy for “Costs”.

Impairment 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.

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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 under “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 judgements: 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 are not recoverable. Such impairment indicators include 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 proved 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 expenditure 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 segment, require judgement 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 expected future cash flows used for impairment analyses are based on judgemental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset.

For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. When appropriate according to facts and circumstances management’s estimate could also include risk-adjusted unproved reserves. The estimate of the future amount of production is based on assumptions related to future commodity prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil and gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent specialised analysts and on management’s forecasts about the evolution of the supply and demand fundamentals.

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 14 — Impairment review of tangible and intangible assets and right-of-use assets.

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.

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At initial recognition, a financial asset is measured at its fair value plus, in the case of a financial asset not at fair value through profit or loss, 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.

A financial asset represented by a debt instrument that is neither measured at amortised cost nor at FVTOCI, is measured at fair value through profit or loss (hereinafter FVTPL); financial assets held for trading fall into this category. Interest income on assets held for trading contributes to the fair value measurement of the instrument and is recognised in “Finance income (expense)”, within “Net finance income (expense) from financial assets held for trading”.

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.

Receivables and other financial assets measured at amortised cost are presented on the balance sheet net of their loss allowance.

The expected credit loss model is also adopted for issued financial guarantee contracts not measured at FVTPL. Expected credit losses recognised on issued financial guarantees are not material.

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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 (impairment losses) 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 judgements: 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 7 — 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.

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.

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

For 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.

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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 and loss account. 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

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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 at 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 expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The change in provisions due to the passage of time is recognised within “Finance income (expense)”.

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 Group has a legal or constructive obligation and when a reliable estimate can be made.

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.

Significant accounting estimates and judgements: 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

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dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgements 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 discount rate used to determine the provision and the timing of future cash outflows, as well as any related update, are based on complex managerial judgements.

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, well-plugging, abandonment and site restoration of the Exploration & Production segment. Any decommissioning and restoration provisions associated with the other segments’ assets are generally not recognised, as the obligations, given their indeterminate settlement dates, also considering the strategy to reconvert plants in order to produce low carbon products, cannot be reliably measured. In this regard, Eni performs periodic reviews for any changes in facts and circumstances that might require recognition of a decommissioning and restoration provision.

As other oil and gas companies, 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.26

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 judgements 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.

With reference to the environmental liabilities assumed, the expected operating costs to be incurred for managing groundwater treatment plants are not included in the estimates of environmental liabilities because it is not possible to reliably define a time horizon within which the operations of the plant will be terminated. In this regard, Eni performs periodic reviews for any changes in facts and circumstances, including changes in regulatory framework and technology, that might require the recognition of the environmental liability.

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Net interest includes the return on plan assets and the interest cost to be recognised in the profit and loss account. 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.

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 judgements: employee benefits and share-based payments

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. 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.

Differences in the amount of the net defined benefit liability (asset), deriving from 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 judgements, the assumptions to be adopted.

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.

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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 interest27. 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.

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.

The payment of accrued interest is required upon the occurrence of events under the issuer’s control such as, for example, a distribution of dividends to shareholders.

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Significant accounting estimates and judgements: 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 mainly 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. 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. 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) 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. 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 tax rates and the 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

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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 judgements: 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 judgements by management. After the initial recognition, these liabilities are periodically reviewed for any changes in facts and circumstances.

Management makes complex judgements 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 their 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

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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 equity-accounted 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.

Significant accounting estimates and judgements: 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 judgement 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. Assets and liabilities are classified as current when: (i) they are

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expected to be realised/settled in the entity’s normal operating cycle or within twelve months after the balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be realised/settled within twelve months after the balance sheet date; on the contrary they are classified as non-current.

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 effective from January 1, 2020 and adopted by Eni, did not have a material impact on the Consolidated Financial Statements. In this regard, also the earlier application in 2020 of the amendments to IFRS 16 “Covid-19-Related Rent Concessions” was immaterial to the Consolidated Financial Statements.

4 IFRSs not yet adopted

On May 18, 2017, the IASB issued IFRS 17 “Insurance Contracts” (hereinafter IFRS 17), which sets out the accounting for the insurance contracts issued and the reinsurance contracts held. On June 25, 2020, the IASB issued the amendments to IFRS 17 “Amendments to IFRS 17” and the amendments to IFRS 4 “Extension of the Temporary Exemption from Applying IFRS 9”, related to insurance activities, providing, among others, the deferral of the effective date of IFRS 17 by two years. Therefore, IFRS 17, which replaces IFRS 4 “Insurance Contracts”, shall be applied for annual reporting periods beginning on or after January 1, 2023.

On January 23, 2020, the IASB issued the amendments to IAS 1 “Classification of Liabilities as Current or Non-current” (hereinafter the amendments), which clarify how to classify debt and other liabilities as current or non-current. Because of further amendments issued on July 15, 2020 (“Classification of Liabilities as Current or Non-current — Deferral of Effective Date”), the amendments shall be applied for annual reporting periods beginning on or after January 1, 2023.

On May 14, 2020, the IASB issued:

•

the amendments to IAS 37 “Onerous Contracts — Cost of Fulfilling a Contract” (hereinafter the amendments), aimed to provide clarifications for the purpose of assessing whether a contract is onerous. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2022;

•

the amendments to IAS 16 “Property, Plant and Equipment: Proceeds before Intended Use” (hereinafter the amendments), aimed to state that the proceeds from selling items produced while the company is preparing the asset for its intended use shall be recognised in the profit and loss account, together with the related production costs. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2022;

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the amendments to IFRS 3 “Reference to the Conceptual Framework” (hereinafter the amendments), aimed to: (i) replace all remaining references to the previous versions of the IFRS Framework with references to the new Conceptual Framework for Financial Reporting included

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in IFRS 3; (ii) provide clarifications on the requirements for recognising, at the acquisition date, provisions, contingent liabilities and levies assumed in a business combination; (iii) state explicitly that a contingent asset acquired in a business combination cannot be recognised. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2022;

•

the document “Annual Improvements to IFRS Standards 2018-2020”, which includes, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2022.

On August 27, 2020, the IASB issued the amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 “Interest Rate Benchmark Reform — Phase 2” (hereinafter the amendments), aimed to provide practical expedients and temporary exceptions from the application of some IFRS requirements related to financial instruments measured at amortised cost and/or hedging relationships modified as a consequence of the interest rate benchmark reform, The amendments shall be applied for annual reporting periods beginning on or after January 1, 2021.

On February 12, 2021, the IASB issued:

•

the amendments to IAS 1 and IFRS Practice Statement 2 “Disclosure of Accounting Policies” (hereinafter the amendments), aimed to provide clarifications on identifying the material accounting policies to be disclosed in the financial statements. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2023;

•

the amendments to IAS 8 “Definition of Accounting Estimates” (hereinafter the amendments), which introduce the definition of accounting estimates essentially to clarify how to distinguish changes in accounting policies from changes in accounting estimates. The amendments shall be applied for annual reporting periods beginning on or after January 1, 2023.

Eni is currently reviewing the IFRSs not yet adopted in order to determine the likely impact on the Consolidated Financial Statements.

5 Cash and cash equivalents

Cash and cash equivalents of €9,413 million (€5,994 million at December 31, 2019) included financial assets with maturity generally of up to three months at the date of inception amounting to €6,913 million (€3,984 million at December 31, 2019) and mainly included short-term deposits in euro and U.S. dollars with financial institutions, having notice of more than 48 hours, to meet the Group’s short-term financing needs.

Expected credit losses on deposits with banks and financial institutions measured at amortized cost are immaterial.

Restricted cash amounted to €198 million (same amount as of December 31,2019) in relation to foreclosure measures by third parties.

The average maturity of bank deposits in euro of €5,948 million was 50 days and the effective interest rate was a negative 0.4%; the average maturity of bank deposits in U.S. dollars of €944 million was 8 days with an effective interest rate of 0.25%.

6 Financial assets held for trading

(€ million)	December 31, 2020		December 31, 2019
Bonds issued by sovereign states		1,223		1,462
Other		4,279		5,298
		5,502		6,760

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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 coping with unexpected fund requirements or difficulties in accessing financial markets. The management of this liquidity reserve is performed through trading activities in view of the 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 €1,361 million (€1,347 million at December 31, 2019).

The breakdown by currency is provided below:

(€ million)	December 31, 2020		December 31, 2019
Euro		3,731		4,272
U.S. dollars		1,688		2,279
Other currencies		83		209
		5,502		6,760

The breakdown by issuing entity and credit rating is presented below:

	Nominal value (€ million)		Fair Value (€ million)		Rating – Moody’s	Rating – S&P
Quoted bonds issued by sovereign states
Fixed rate bonds
Italy		499		506	Baa3	BBB
Chile		187		192	A1	A+
Other(*)		168		172	from Aaa to Baa1	from AAA to A-
		854		870
Floating rate bonds
Italy		253		255	Baa3	BBB
Germany		56		55	Aaa	AAA
Other		43		43	from Aaa to Baa3	from AA+ to BBB
		352		353
Total quoted bonds issued by sovereign states		1,206		1,223
Other Bonds
Fixed rate bonds
Quoted bonds issued by industrial companies		974		992	from Aa2 to Baa3	from AA to BBB-
Quoted bonds issued by financial and insurance companies		893		910	from Aa1 to Baa3	from AA+ to BBB-
Other bonds		54		55	from Aaa to Baa3	from AAA to BBB-
		1,921		1,957
Floating rate bonds
Quoted bonds issued by industrial companies		791		787	from Aa1 to Baa3	from AA+ to BBB-
Quoted bonds issued by financial and insurance companies		1,298		1,301	from Aa1 to Baa3	from AA+ to BBB-
Other bonds		234		234	from Aaa to Baa3	from AAA to BBB-
		2,323		2,322
Total other bonds		4,244		4,279
Total other financial assets held for trading		5,450		5,502

(*)

Amounts included herein are lower than €50 million.

The fair value hierarchy is level 1 for €5,248 million and level 2 for €254 million. During 2020, there were no significant transfers between the different hierarchy levels of fair value.

7 Trade and other receivables

(€ million)	December 31, 2020		December 31, 2019
Trade receivables		7,087		8,519
Receivables from divestments		21		30
Receivables from joint ventures in exploration and production activities		2,293		2,637
Other receivables		1,525		1,687
		10,926		12,873

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Generally, trade receivables do not bear interest and provide payment terms within 180 days.

Trade receivables decreased by €1,432 million due to the drop in prices of hydrocarbons.

At December 31, 2020, Eni sold without recourse receivables due in 2021 for €1,377 million (€1,782 million at December 31, 2019 due in 2020). Derecognized receivables in 2020 related to the Refining & Marketing and Chemical segment for €730 million, to the Eni gas e luce, Power & Renewables segment for €324 million and to the Global Gas & LNG Portfolio segment for €323 million.

Receivables from joint ventures in exploration and production activities included amounts due by partners in unincorporated joint operation in Nigeria of €1,015 million (€1,052 million at December 31, 2019) in respect of the contractual recovery of expenditures incurred at certain projects operated by Eni. The Nigerian national oil company NNPC owed an amount to Eni of €605 million (€764 million at December 31, 2019), in relation to past investments. About half of this amount is subject to a “Repayment Agreement”, whereby Eni is to be reimbursed through the sale of the entitlement attributable to NNPC in certain rig-less petroleum initiatives with low mineral risk, with an expected completion of the reimbursement plan within the next two/three years based on Eni’s Brent price scenario. The receivable is stated net of a discount factor equal to 8%, calculated based on the risk of the underlying mineral initiative. The amounts past due related to current investment activities were assessed based on more conservative assumptions than the ones adopted in previous reporting periods to factor in an increased counterparty risk due to COVID-19 developments. A privately held Nigerian oil company owed us €134 million (€113 million at December 31, 2019) which were past due at the reporting date. These amounts were stated net of a provision based on the loss given default (LGD) defined by Eni for international oil companies in a default state.

Receivables from other counterparties comprised: (i) recoverable amounts for €376 million (€373 million at December 31, 2019) of certain overdue trade receivables towards the state-owned oil company of Venezuela, PDVSA, in relation to gas equity volumes supplied 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 estimated on the basis of average recovery percentages obtained by creditors in the context of sovereign defaults, adjusted to reflect the strategic value of the oil&gas sector, and also applied for assessing the recoverability of the carrying amount of the investment and the long-term interest in the initiative, as described in note 16 — Other financial assets. Risks associated with the complex financial outlook of the Country and the deteriorated operating environment were taken into account in the estimation of the expected loss by assuming a deferral in the timing of collection of future revenues and overdue credit amounts which resulted in an expected credit loss rate of about 53%. During the year the percentages of collection of gas sales by the joint venture were in line with the estimated assumption; (ii) amounts to be received from customers following the triggering of the take-or-pay clause of long-term gas supply contracts for €325 million (€104 million at December 31, 2019).

Trade and other receivables stated in euro and U.S. dollars amounted to €5,553 million and €4,304 million, respectively.

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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						Defaulted receivables		Eni gas e luce customers		Total
(€ million)	Low risk		Medium Risk		High Risk		Defaulted receivables		Eni gas e luce customers		Total
December 31, 2020
Business customers		1,398		2,746		432		1,351				5,927
National Oil Companies and public administrations		841		620		7		2,653				4,121
Other counterparties		1,243		450		28		141		2,173		4,035
Gross amount		3,482		3,816		467		4,145		2,173		14,083
Allowance for doubtful accounts		(32)		(21)		(29)		(2,429)		(646)		(3,157)
Net amount		3,450		3,795		438		1,716		1,527		10,926
Expected loss (% net of counterpart risk mitigation factors)		0.9		0.6		6.2		58.6		29.7		22.4
December 31, 2019
Business customers		1,922		2,882		840		1,396				7,040
National Oil Companies and public administrations		1,201		472		244		2,710				4,627
Other counterparties		1,646		103		381		217		2,105		4,452
Gross amount		4,769		3,457		1,465		4,323		2,105		16,119
Allowance for doubtful accounts		(13)		(4)		(16)		(2,547)		(666)		(3,246)
Net amount		4,756		3,453		1,449		1,776		1,439		12,873
Expected loss (% net of counterpart risk mitigation factors)		0.3		0.1		1.1		58.9		31.6		20.1

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.

Management has reviewed its assumptions underlying the recoverability of outstanding receivables in light of the widespread economic and financial impacts of the COVID-19 pandemic crisis on the counterparty risk. The review of recoverability assumptions led to both an extension in the timing of credit collection (generally of one year) and a step-up in the probabilities of default applicable across the Company’s customer classes. These updated assumptions were based on accumulated experience, independent assessments of the expected increase in the probability of default of commercial counterparts over a twelve-month time horizon to factor in the financial impact of the ongoing crisis, as well as updated evaluations of the probability of unfavorable developments in the operating environment of the main countries where Eni is conducting oil&gas operations leading to an increased risk applicable to our counterparts national oil companies. With regard to customers of the Eni gas e luce business line, the recoverability assessments incorporate the most updated information relating to the performance in credit collection and the ageing of overdue amounts.

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The exposure to credit risk and expected losses relating to customers of the Eni gas e luce business line was assessed based on a provision matrix as follows:

	Ageing
(€ million)	Not-past due		from 0 to 3 months		from 3 to 6 months		from 6 to 12 months		over 12 months		Total
December 31, 2020
Customers – Eni gas e luce:
- Retail		1,155		105		50		102		366		1,778
- Middle		75		16		3		8		232		334
- Other		61										61
Gross amount		1,291		121		53		110		598		2,173
Allowance for doubtful accounts		(46)		(23)		(22)		(57)		(498)		(646)
Net amount		1,245		98		31		53		100		1,527
Expected loss (%)		3.6		19.0		41.5		51.8		83.3		29.7
December 31, 2019
Customers – Eni gas e luce:
- Retail		991		105		60		86		376		1,618
- Middle		93		29		4		14		263		403
- Other		76		3		1		2		2		84
Gross amount		1,160		137		65		102		641		2,105
Allowance for doubtful accounts		(16)		(27)		(26)		(49)		(548)		(666)
Net amount		1,144		110		39		53		93		1,439
Expected loss (%)		1.4		19.7		40.0		48.0		85.5		31.6

Trade and other receivables are stated net of the allowance for doubtful accounts which has been determined considering the counterpart risk mitigation factors amounting to €1,016 million (€2,914 million at December 31, 2019):

(€ million)	2020		2019
Allowance for doubtful accounts – beginning of the year		3,246		3,150
Additions on trade and other performing receivables		112		95
Additions on trade and other defaulted receivables		231		525
Deductions on trade and other performing receivables		(82)		(119)
Deductions on trade and other defaulted receivables		(275)		(484)
Other changes		(75)		79
Allowance for doubtful accounts – end of the year		3,157		3,246

Additions to allowance for doubtful accounts on trade and other performing receivables related for €84 million (€65 million in 2019) to Eni gas e luce business line, particularly in the retail business; the increase compared to 2019 is due to the effects of the economic crisis on the solvency of small and medium-sized companies.

Additions to allowance for doubtful accounts on trade and other defaulted receivables related to: (i) the Exploration & Production segment for €118 million (€339 million in 2019) and were in relation with receivables for the supply of equity hydrocarbons to State-owned companies and receivables towards joint operators, State oil Companies and local private companies for cash calls in oil projects operated by Eni; (ii) to the retail gas and power business for €97 million (€87 million in 2019).

Utilizations of allowance for doubtful accounts on trade and other performing and defaulted receivables amounted to €357 million (€603 million in 2019) and mainly related to the Eni gas e luce business line for €200 million (€343 million in 2019), in particular utilizations against charges of €178 million (€319 million in 2019) mainly in the retail business. Utilizations in Exploration & Production segment of €101 million (€177 million in 2019) related for €73 million to the derecognition of receivables from PDVSA following in-kind refunds.

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Net (impairment losses) reversals of trade and other receivables are disclosed as follows:

(€ million)	2020		2019		2018
Net (impairment losses) reversals of trade and other receivables
New or increased provisions		(343)		(620)		(498)
Net credit losses		(36)		(45)		(37)
Reversals		153		233		120
		(226)		(432)		(415)

Receivables with related parties are disclosed in note 36 — Transactions with related parties.

8 Current and non-current inventories

Current inventories are disclosed as follows:

(€ million)	December 31, 2020		December 31, 2019
Raw and auxiliary materials and consumables		706		950
Consumables for infrastructure and facility maintenance of perforation activities		1,580		1,477
Finished products and goods		1,603		2,284
Other		4		23
		3,893		4,734

Raw and auxiliary materials and consumables include oil-based feedstock, catalysts and other consumables pertaining to refining and chemical activities.

Materials and supplies include materials to be consumed in drilling activities and spare parts to the Exploration & Production segment for €1,463 million (€1,359 million at December 31, 2019).

Finished products and goods included natural gas and oil products for €874 million (€1,467 million at December 31, 2019) and chemical products for €443 million (€547 million at December 31, 2019).

Inventories are stated net of write-down provisions of €348 million (€377 million at December 31, 2019).

Inventories held for compliance purposes of €995 million (€1,371 million at December 31, 2019) related to Italian subsidiaries for €977 million (€1,353 million at December 31, 2019) 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 due to the alignment of the book values to their net realizable values at year-end, which were affected by the drop in oil and hydrocarbons prices.

9 Income tax receivables and payables

(€ million)

December 31, 2020

December 31, 2019

Receivables

Payables

Receivables

Payables

Current

Non Current

Current

Non Current

Current

Non Current

Current

Non Current

Income taxes

184

153

243

360

192

173

456

454

Income taxes are described in note 32 — Income tax expense.

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 €254 million (€362 million at December 31, 2019).

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10 Other assets and liabilities

(€ million)	December 31, 2020								December 31, 2019
	Assets				Liabilities				Assets				Liabilities
	Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current
Fair value of derivative financial instruments		1,548		152		1,609		162		2,573		54		2,704		50
Contract liabilities						1,298		394						1,669		456
Other Taxes		450		181		1,124		26		766		223		1,411		63
Other		688		920		841		1,295		633		594		1,362		1,042
		2,686		1,253		4,872		1,877		3,972		871		7,146		1,611

The fair value related to derivative financial instruments is disclosed in note 23 — Derivative financial instruments and hedge accounting.

Assets related to other current taxes included VAT for €475 million, of which €315 million are current, and advances made in December (€742 million at December 31, 2019, of which €557 million current).

Other assets include: (i) 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 within the next 12 months for €53 million, and beyond 12 months for €651 million (€174 million at December 31, 2019); in 2020 the Company opted to increase the take-or-pay advance with a view of optimizing its gas portfolio and motivated by the reduction in gas demand due to the COVID-19 pandemic, expecting to recover the underlying volumes beyond the next year; (ii) underlifting positions of the Exploration & Production segment of €338 million (€323 million at December 31, 2019); (iii) non-current receivables for investing activities for €11 million (same amount as of December 31, 2019).

Contract liabilities included: (i) advances denominated in local currency of €546 million (€1,228 million at December 31, 2019) to offset future supplies of equity hydrocarbons to our Egyptian State-owned partners in relation to the operations of Eni’s Concession Agreements in the Country, in particular, among these, the Zohr project. In 2020, the decrease is due to the offsetting with the gas invoices for the sale of equity production, considering the substantial completion of the investment activities; (ii) the current portion of advances received by Engie SA (former Suez) relating to a long-term agreement for supplying natural gas and electricity for €62 million (€64 million at December 31, 2019); the non-current portion amounted to €393 million (€455 million at December 31, 2019). Revenues recognized during the year related to contract liabilities stated at December 31, 2019 are indicated in note 28 - Revenues and other income.

Liabilities related to other current taxes include excise duties and consumer taxes for €516 million (€628 million at December 31, 2019) and VAT liabilities for €212 million (€311 million at December 31, 2019).

Other current liabilities included overlifting imbalances of the Exploration & Production segment for €559 million (€917 million at December 31, 2019).

Other non-current liabilities included: (i) liabilities for prepaid revenues and income for €323 million (€420 million at December 31, 2019); (ii) the value of gas not withdrawn by customers due to the triggering of the take-or-pay clause provided for by the relevant long-term contracts, the underlying volumes of which are expected to be withdrawn within the next 12 months for €65 million and beyond 12 months for €372 million (€148 million at December 31, 2019); (iii) cautionary deposits for € 261 million (€265 at December 31, 2019), of which €228 million from retail customers for the supply of gas and electricity (€231 million at December 31, 2019).

Transactions with related parties are described in note 36 — Transactions with related parties.

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11 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
2020
Net carrying amount – beginning of the year		1,218		46,492		3,632		1,563		7,412		1,875		62,192
Additions		12		6		229		265		3,127		768		4,407
Depreciation capitalized								4		100				104
Depreciation(*)		(55)		(5,642)		(508)								(6,205)
Reversals		13		183		342				98		12		648
Impairment		(82)		(1,551)		(972)				(567)		(582)		(3,754)
Write-off						(1)		(296)		(7)		(1)		(305)
Currency translation differences		(2)		(3,325)		(75)		(119)		(605)		(14)		(4,140)
Initial recognition and changes in estimates				870				(9)		94				955
Transfers		39		2,677		755		(47)		(2,630)		(794)
Other changes		(15)		(62)		(103)		(20)		96		145		41
Net carrying amount – end of the year		1,128		39,648		3,299		1,341		7,118		1,409		53,943
Gross carrying amount – end of the year		4,082		136,468		28,839		1,341		11,169		2,742		184,641
Provisions for depreciation and impairments		2,954		96,820		25,540				4,051		1,333		130,698
2019
Net carrying amount – beginning of the year		1,274		42,856		3,901		1,267		9,195		1,809		60,302
Additions		12		144		223		508		6,170		992		8,049
Depreciation capitalized								14		202				216
Depreciation(*)		(60)		(6,435)		(537)								(7,032)
Reversals		44		65		69				65		139		382
Impairment		(47)		(659)		(500)				(669)		(537)		(2,412)
Write-off						(5)		(216)		(49)				(270)
Disposals		(1)		(3)		(1)		(22)		(80)		(6)		(113)
Currency translation differences		2		815		21		24		181		1		1,044
Initial recognition and changes in estimates				2,028				25		21				2,074
Transfers		42		7,568		597		(42)		(7,526)		(639)
Other changes		(48)		113		(136)		5		(98)		116		(48)
Net carrying amount – end of the year		1,218		46,492		3,632		1,563		7,412		1,875		62,192
Gross carrying amount – end of the year		4,067		144,789		28,191		1,563		11,406		2,799		192,815
Provisions for depreciation and impairments		2,849		98,297		24,559				3,994		924		130,623

(*)

Before capitalization of depreciation of tangible assets.

Capital expenditures included capitalized finance expenses of €73 million (€93 million in 2019) related to the Exploration & Production segment for €51 million (€71 million in 2019). The interest rate used for capitalizing finance expense ranged from 1.3% to 2.2% (2.6% to 2.8% at December 31, 2019).

Capital expenditures primarily related to the Exploration & Production segment for €3,444 million (€6,889 million in 2019) and included bonuses for €57 million of which €55 million for the acquisition of unproved mineral interest in Algeria.

Capital expenditures by industry segment and geographical area of destination are reported in note 35 — Segment information and information by geographical area.

The main depreciation rates used were substantially unchanged from the previous year and ranged as follows:

(%)
Buildings					2 – 10
Mineral exploration wells and plants					UOP
Refining and chemical plants					3 – 17
Gas pipelines and compression stations					4 – 12
Power plants					4 – 5
Other plant and machinery					6 – 12
Industrial and commercial equipment					5 – 25
Other assets					10 – 20

The criteria adopted by Eni for determining impairment losses and reversal is reported in note 14 — Impairment review of tangible and intangible assets and right-of-use assets.

Currency translation differences related to subsidiaries which utilize the U.S. dollar as functional currency (€4,068 million).

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Initial recognition and change in estimates include the increase in the asset retirement cost of Exploration & Production segment mainly due to the reduction in discount rates and in estimated costs for social projects to be incurred in respect to the commitments being formalized between Eni SpA and the Basilicata region following to the development plan of oilfields in Val d’Agri relating to royalties for mineral concessions (€439 million).

Transfers from E&P tangible assets in progress to E&P UOP wells, plant and machinery related for €1,690 million to the commissioning of wells, plants and machinery primarily in Egypt, Italy, Algeria, Iraq, United States, Kazakhstan and Mexico.

Exploration and appraisal activities of 2020 comprised write-offs of unsuccessful exploration wells costs for €296 million mainly in Libya, United States, Angola, Egypt, Oman, Mexico and Lebanon.

Exploration and appraisal activities related for €1,268 million to the costs of suspended exploration wells pending final determination and for €66 million to costs of exploration wells in progress at the end of the year. Changes relating to suspended wells are reported below:

(€ million)	2020		2019		2018
Costs for exploratory wells suspended – beginning of the year		1,246		1,101		1,263
Increases for which is ongoing the determination of proved reserves		408		368		235
Amounts previously capitalized and expensed in the year		(226)		(183)		(61)
Reclassification to successful exploratory wells following the estimation of proved reserves		(48)		(46)		(297)
Disposals				(15)		(6)
Changes in the scope of consolidation						(58)
Reclassification to assets held for sale						(24)
Currency translation differences		(112)		21		49
Costs for exploratory wells suspended – end of the year		1,268		1,246		1,101

The following information relates to the stratification of the suspended wells pending final determination (ageing):

	2020				2019				2018
	(€ million)		(number of wells in Eni’s interest)		(€ million)		(number of wells in Eni’s interest)		(€ million)		(number of wells in Eni’s interest)
Costs capitalized and suspended for exploratory well activity
- within 1 year		157		6.7		185		7.7		111		7.0
- between 1 and 3 years		250		11.0		171		6.4		87		2.9
- beyond 3 years		861		19.3		890		26.4		903		24.2
		1,268		37.0		1,246		40.5		1,101		34.1
Costs capitalized for suspended wells
- fields including wells drilled over the last 12 months		157		6.7		185		7.7		111		7.0
- fields for which the delineation campaign is in progress		631		14.9		556		11.3		217		4.7
- fields including commercial discoveries that proceeds to sanctioning		480		15.4		505		21.5		773		22.4
		1,268		37.0		1,246		40.5		1,101		34.1

Suspended wells costs awaiting a final investment decision amounted to €480 million and primarily related to the exploration costs incurred for the Mamba discovery in Mozambique’s offshore Area 4 (€151 million), for which the venture partners are completing the activities for sanctioning the project. The other suspended costs refer to several initiatives ongoing in the main countries of presence (Nigeria, Congo, Egypt and Indonesia), none of which represented an individually significant amount.

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Unproved mineral interests, comprised in 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		Total
2020
Book amount at the beginning of the year		253		939		139		162		115		19		535		2,162
Additions										55		2				57
Net (impairments) reversals		(25)				(134)		(37)								(196)
Reclassification to proved mineral interest						(2)				(61)		(2)		(25)		(90)
Currency translation differences		(25)		(79)		(3)		(11)		(9)		(1)		(42)		(170)
Book amount at the end of the year		203		860				114		100		18		468		1,763
2019
Book amount at the beginning of the year		769		921		77		103		77		29		502		2,478
Additions								97		135		1		23		256
Net (impairments) reversals		(533)				65		(27)								(495)
Reclassification to proved mineral interest						(4)		(14)		(99)		(12)				(129)
Currency translation differences		17		18		1		3		2		1		10		52
Book amount at the end of the year		253		939		139		162		115		19		535		2,162

Unproved mineral interests comprised the Oil Prospecting License 245 property (“OPL 245”), offshore Nigeria, for €800 million corresponding to the price paid in 2011 to the Nigerian Government to acquire a 50% interest in the property, with another international oil company acquiring the remaining 50%. As of December 31, 2020, the net book value of the property amounted to €1,085 million, including capitalized exploration costs and pre-development costs. The acquisition of OPL 245 is subject to judicial proceedings in Italy and in Nigeria for alleged corruption and money laundering in respect of the Resolution Agreement signed on April 29, 2011, relating to the purchase of the license. This proceeding is disclosed in note 27 — Guarantees, Commitments and Risks — legal proceedings. The impairment test of the asset confirmed the book value. The impairment review was based on the assumption that the exploration licence due to expire in May 2021 will be renewed or converted into a mining licence. Eni filed an application for renewal/conversion of the licence in compliance with the contractual terms. Considering the inaction of the Nigerian authorities in charge of the matter towards the legitimate request of the Company and the closeness of the expiry date of the licence, in September 2020 Eni started an arbitration at ICSID, the international centre for settlement of investment disputes, to protect the value of its asset.

Accumulated provisions for impairments amounted to €20,343 million (€18,226 million at December 31, 2019).

Property, plant and equipment include assets subject to operating leases for €358 million, essentially relating to service stations of the Refining & Marketing business line.

At December 31, 2020, Eni pledged property, plant and equipment for €24 million to guarantee payments of excise duties (same amount as of December 31, 2019).

Government grants recorded as a decrease of property, plant and equipment amounted to €103 million (€112 million at December 31, 2019).

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 27 — Guarantees, commitments and risks — Liquidity risk.

Property, plant and equipment under concession arrangements are described in note 27 — Guarantees, commitments and risks — Assets under concession arrangements.

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12 Right-of-use assets and lease liabilities

(€ million)	Floating production storage and offloading vessels (FPSO)		Drilling rig		Naval facilities and related logistic bases for oil and gas transportation		Motorway concessions and service stations		Oil and gas distribution facilities		Office buildings		Vehicles		Other		Total
2020
Net carrying amount – beginning of the year		3,153		313		497		460		6		707		32		181		5,349
Additions		79		193		281		49		22		65		24		95		808
Depreciation(a)		(232)		(189)		(252)		(57)		(2)		(118)		(22)		(56)		(928)
Impairment losses								(21)		(15)						(11)		(47)
Currency translation differences		(251)		(13)		(13)						(8)				(7)		(292)
Other changes		(77)		(60)		(67)		(7)				6		(2)		(40)		(247)
Net carrying amount at the end of the year		2,672		244		446		424		11		652		32		162		4,643
Gross carrying amount at the end of the year		3,107		528		927		573		29		859		65		293		6,381
Provisions for depreciation and impairment		435		284		481		149		18		207		33		131		1,738
2019
First adoption IFRS 16		3,294		346		569		462		7		720		43		215		5,656
Reclassifications								30								16		46
Reclassifications to assets held for sale																(13)		(13)
Net carrying amount at January 1, 2019		3,294		346		569		492		7		720		43		218		5,689
Additions		32		192		219		54		1		108		22		56		684
Depreciation(a)		(240)		(224)		(272)		(61)		(1)		(115)		(23)		(63)		(999)
Impairment losses								(13)								(28)		(41)
Currency translation differences		67		6		4		2				3				3		85
Other changes				(7)		(23)		(14)		(1)		(9)		(10)		(5)		(69)
Net carrying amount at December 31, 2019		3,153		313		497		460		6		707		32		181		5,349
Gross carrying amount		3,393		528		757		532		7		806		54		274		6,351
Provisions for depreciation and impairment		240		215		260		72		1		99		22		93		1,002

(a)

Before capitalization of depreciation of tangible assets

Right-of-use assets (RoU) related: (i) for €3,274 million (€3,895 million at December 31, 2019) 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 Angola (Block 15/06 West and East hub) with expiry date between 9 and 16 years including a renewal option and in addition the lease component of long-term leases of offshore rigs; (ii) for €788 million (€831 million at December 31, 2019) to the Refining & Marketing and Chemical segment relating to motorway concessions, 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 €526 million (€574 million at December 31, 2019) to the Corporate and other activities segment mainly regarding property rental contracts.

The main leasing contracts signed for which the asset is not yet available concerns: (i) a contract with a nominal value of €1.7 billion relating to an FPSO vessel that will be deployed for the development of Area 1 in Mexico. The asset is expected to enter under the Group’s control and be accounted as RoU in 2021, expiring in 2040; (ii) a contract with a nominal value of €438 million relating to leasing of office buildings with an expiry date of 20 years including an extension option of 6 years; (iii) a contract for the use of a FLNG naval unit, signed by the joint operation Mozambique Rovuma Venture SpA (Eni’s interest 35.71%), for the development of the Coral discovery in the offshore of Mozambique, the amount of which will be determined based on the final cost payments incurred for the realization of the asset by the associated company Coral FLNG SA and the financial charges relating to the debt of this company towards Coral South FLNG DMCC. The commencement date of the lease is expected in 2022, corresponding to the start of production of the Coral field.

The 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 €302 million; (ii) extension options related to service stations for the sale of oil products of €148 million; (iii) other extension options related to concessions of land for €60 million and ancillary assets in the upstream business for €48 million.

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Liabilities for leased assets were as follows:

(€ million)	Current portion of long-term lease liabilities		Long-term lease liabilities		Total
2020
Book amount at the beginning of the year		889		4,759		5,648
Additions				808		808
Decreases		(866)		(3)		(869)
Currency translation differences		(40)		(269)		(309)
Other changes		866		(1,126)		(260)
Book amount at the end of the year		849		4,169		5,018
2019
First adoption IFRS 16		665		4,991		5,656
Reclassifications		132		36		168
Reclassifications to liabilities directly associated with assets held for sale		(3)		(10)		(13)
Carrying amount at January 1, 2019		794		5,017		5,811
Additions				668		668
Decreases		(875)		(2)		(877)
Currency translation differences		10		77		87
Other changes		960		(1,001)		(41)
Carrying amount at December 31, 2019		889		4,759		5,648

Lease liabilities related for €1,652 million (€1,976 million at December 31, 2019) 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 €869 million; (ii) cash payments for the interest portion of €329 million.

Lease liabilities stated in U.S. dollars and euro amounted to €3,447 million and €1,411 million, respectively.

Other changes in right-of-use assets and lease liabilities essentially related to early termination or renegotiation of lease contracts.

The amounts recognised in the profit and loss account consist of the following:

(€ million)	2020		2019
Other income and revenues
Income from remeasurement of lease liabilities		12		6
		12		6
Purchases, services and other
Short-term leases		67		115
Low-value leases		37		39
Variable lease payments not included in the measurement of lease liabilities		7		16
Capitalised direct cost associated with self-constructed assets – tangible assets		(2)		(2)
		109		168
Depreciation and impairments
Depreciation of RoU leased assets		928		999
Capitalised direct cost associated with self-constructed assets – tangible assets		(96)		(210)
Impairment losses of RoU leased assets		47		41
		879		830
Finance income (expense) from leases
Interests on lease liabilities		(347)		(378)
Capitalised finance expense of ROU leased assets – tangible assets		7		17
Net currency translation differences on lease liabilities		24		(6)
		(316)		(367)

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13 Intangible assets

(€ million)	Exploration rights		Industrial patents and intellectual property rights		Other intangible assets		Intangible assets with finite useful lives		Goodwill		Total
2020
Net carrying amount – beginning of the year		1,031		195		568		1,794		1,265		3,059
Additions		18		23		196		237				237
Amortization		(53)		(92)		(130)		(275)				(275)
Impairments		(23)				(7)		(30)		(24)		(54)
Reversals						24		24				24
Write-off		(19)		(5)				(24)				(24)
Changes in the scope of consolidation						7		7		70		77
Currency translation differences		(66)				(3)		(69)		(14)		(83)
Other changes				41		(66)		(25)				(25)
Net carrying amount at the end of the year		888		162		589		1,639		1,297		2,936
Gross carrying amount at the end of the year		1,613		1,623		4,399		7,635
Provisions for amortization and impairment		725		1,461		3,810		5,996
2019
Net carrying amount – beginning of the year		1,081		221		584		1,886		1,284		3,170
Additions		78		23		210		311				311
Amortization		(81)		(93)		(117)		(291)				(291)
Impairments		(19)				(72)		(91)		(26)		(117)
Write-off		(28)		(1)		(1)		(30)				(30)
Currency translation differences		18				1		19		3		22
Other changes		(18)		45		(37)		(10)		4		(6)
Net carrying amount at the end of the year		1,031		195		568		1,794		1,265		3,059
Gross carrying amount at the end of the year		1,748		1,597		4,373		7,718
Provisions for amortization and impairment		717		1,402		3,805		5,924

Exploration rights comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on UOP criteria and are regularly reviewed for impairment. Furthermore, they include the cost of unproved areas which 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 Angola, Albania, United Arab Emirates, Egypt, Oman and the extension of a licence in Gabon.

The breakdown of exploration rights by type of asset was as follows:

(€ million)	December 31, 2020		December 31, 2019
Proved licence and leasehold property acquisition costs		225		291
Unproved licence and leasehold property acquisition costs		653		709
Other mineral interests		10		31
		888		1,031

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.

Other intangible assets comprised: (i) customer acquisition costs relating to Eni gas e luce business line for €262 million (€226 million at December 31, 2019); (ii) concessions, licenses, trademarks and similar items for €88 million (€102 million at December 31, 2019) comprised transmission rights for natural gas imported from Algeria for €25 million (€30 million at December 31, 2019); (iii) capital expenditures in progress on natural gas pipelines for which Eni has acquired transport rights for €78 million (same amount as of December 31, 2019).

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The main amortization rates used were substantially unchanged from the previous year and ranged as follows:

(%)
Exploration rights					UOP
Transport rights of natural gas					3
Other concessions, licenses, trademarks and similar items					3 – 33
Service concession arrangements					20 – 33
Capitalized costs for customer acquisition					17 – 33
Other intangible assets					4 – 20

Cumulative impairments charges at the end of the year amounted to €2,457 million.

The breakdown of goodwill by segment is provided below:

(€ million)	December 31, 2020		December 31, 2019
Eni gas e luce		1,046		981
Exploration & Production		146		190
Refining & Marketing		93		93
Corporate and Other activities		11
Renewables		1		1
		1,297		1,265

An impairment loss of goodwill was recorded in relation to a business combination of the Exploration & Production segment.

Change in the scope of consolidation of goodwill related for €66 million to the acquisition of the 70% stake in Evolvere, a group operating in the business of distributed generation from renewable sources.

Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition.

With regard to the Eni gas e luce business line, which has significant allocated goodwill, the allocation of CGU was carried out as follows:

(€ million)	December 31, 2020		December 31, 2019
Domestic market		904		839
Foreign market		142		142
		1,046		981

Goodwill allocated to the CGU Domestic market was recognized upon the buy-out of the former Italgas SpA minorities in 2003 through a public offering (€706 million). The acquired entity engaged in the retail sale of gas to the residential sector and middle and small-sized businesses in Italy. In addition, further goodwill amounts have been allocated over the years following business combinations with small, local companies selling gas to residential customers in focused territorial reach and municipalities synergic to Eni’s activities, the latest of which was the acquisition of 70% of Evolvere group, operating in the business of distributed generation from renewable sources, in line with the strategy of growing the market share in the retail sector through the diversification of the product mix by offering green electricity. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU, including the allocated goodwill.

The recoverability of the carrying amount of the CGU Domestic market, including the allocated portion of goodwill, was verified comparing 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 perpetuity of the last year of the plan by assuming a nominal long-term growth rate equal to zero, unchanged. These cash flows were discounted by using the post-tax WACC of the retail business adjusted considering the specific country risk for Italy of 4.3%.

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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 €2,856 million of the value in use of the CGU Domestic market with respect to its book value, including the allocated goodwill.

Goodwill allocated to the CGU Foreign market related for €95 million to Eni Gas & Power France SA (former Altergaz SA) operating in France and for €45 million to the acquisition in 2018 of the residual 51% interest in Gas Supply Company Thessaloniki-Thessalia SA operating in Greece, previously participated with a 49% of the share capital. The impairment review performed at the balance sheet date by using a method similar to the CGU Domestic market confirmed the recoverability of the carrying amount of these market CGUs, including the goodwill, by using a post-tax WACC adjusted considering a post-tax country risk for France of 4.6% and 4.8% for Greece.

Post-tax cash flows and discount rates resulted in an assessment that substantially approximated a pre-tax assessment.

14 Impairment review of tangible and intangible assets and right-of-use assets

Management has adopted a conservative stance in elaborating its view of the long-term oil price outlook, considering the risks and uncertainties associated with the post-pandemic recovery and the pace of the energy transition. With the long-term fallout of the pandemic still being evaluated, management sees the prospect of an enduring impact on the global economy, with the potential for weaker demand for energy for a sustained period, because differently from other recessions, the one caused by the pandemic has involved at the same time all cyclical sectors of the economy and the service sector as well with consequent extreme fluctuations in the economic activity.

Eni’s management also has a growing expectation that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system, as countries seek to ‘build back better’ so that their economies will be more resilient in the future.

Based on these considerations, management reviewed on the downside the long-term outlook for oil prices, which is the main driver of investment appraisal and the evaluation of recoverability of the Group’s tangible assets. The revised scenario adopted by Eni forecasts a long-term Brent price of 60 $/bbl in 2023 real terms, compared to a previous level of 70$, used in the impairment test in 2019. In 2021 and 2022, Brent prices are set at 50 and 55 $/bbl, respectively. The gas price of the Italian spot market has been projected at 5.5 $/mmBTU in 2023, down from the previous assumption of 7.8$/mmBTU. Management also revised downwards its expectations of future refining margins considering the collapse in the consumption of fuels driven by the pandemic.

The discount rates of future cash flows associated with the use of the assets were estimated on the basis of Eni’s weighted average cost of capital, adjusted to discount the specific risks of the operating context of the Group’s countries of activity (WACC adjusted). Eni’s WACC for 2020 of 6.7% decreased compared to 2019 (7.4%), mainly due to the decline in the yields of risk-free assets of benchmark countries, which turned negative. This trend was mitigated by the greater weight attributed to the short-term volatility of Eni stock (beta determined from independent sources) which compared to the prior year is affected by a greater perceived risk of the oil&gas sector due to climate-related risks and structural weaknesses of the industry, also amplified by the pandemic crisis.

The cash flows of the assets have been estimated based on the approved business plans and the residual useful life of the reserves or industrial plants as described in Note 1 — Significant accounting policies, estimates and judgements — Impairment of non-financial assets.

In consideration of the generalized presence of impairment indicators in all Eni’s business sectors, including the evidence that as of December 31, 2020, Eni’s market capitalization was lower than the book value of the consolidated net assets, and the company policy to regularly test the recoverability of carrying amounts, an impairment test covering 100% of the CGUs was performed.

In the Exploration & Production sector, impairment losses of assets in production or development were recognized for €1,888 million, mainly due to the revision of long-term hydrocarbons prices and the reduced capital expenditures to develop reserves, as well as downward revisions of reserves. The most

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significant amounts were recorded at properties in Italy (€566 million), Algeria (€409 million), Congo (€306 million), USA (€232 million) and Turkmenistan (€202 million). The post-tax WACC used ranges from a minimum of about 6% for Italy/USA to a range of 7–8% for the other countries, which are redetermined in a range of 6-14% pre-tax.

In the Refining & Marketing business, impairment losses of refining plants were recorded for € 1,225 million, mainly related to the Sannazzaro Refinery, driven by the weak fundamentals of the European industry, explained by: the crisis in fuel consumptions due to the pandemic; overcapacity, competitive pressure from Asian and Middle Eastern producers with more efficient scale and cost structures; market dislocations, that have reduced the supply of medium/heavy crude oils, penalizing the profitability of conversion cycles. The pre-tax and post-tax discount rate relating to the Italian refineries is 6.3%.

In addition, the recoverability of the carrying amounts of oil&gas activities was assessed also taking into account the expected expenditure for participating to forestry conservation projects, consistent with Eni’s decarbonization targets, the achievement of which includes participating in initiatives for the conservation and repopulation of primary and secondary forests to obtain carbon credits, certified according to international standards. Management expects a gradual ramp up of these initiatives in the medium-long term with the aim of having a portfolio of forestry projects by 2030 from which to obtain an annual amount of carbon credits capable of covering the deficit of residual direct and indirect emissions (“Scope 1 and 2”) of the Exploration & Production sector for the purposes of carbon neutrality of equity production from 2030 onwards. The expenditures for the purchase of carbon credits are considered part of the operating costs of the Exploration & Production sector with reference to the whole sector considered as a single CGU. Net of these projected costs until the end of the residual life of the reserves, the overall headroom of the Exploration & Production sector determined on the basis of the assumptions of the impairment test is reduced by 4.6%.

The reasonableness of the outcome of the impairment review made by Eni at its oil&gas activities was assessed on the basis of a stress test analysis performed using the decarbonization scenario developed by the International Energy Agency (IEA) in its Sustainable Development Scenario in the in the World Energy Outlook (WEO) 2020 which draws a pathway and a set of actions consistent with the goal of the 2015 COP21 Paris Agreement on climate. The IEA SDS scenario is a well-established set of assumptions available on the market place relating to the decarbonization of the world economy. The VIUs of Eni’s reserves were reassessed with the projections estimated by the IEA of hydrocarbon prices and the purchase cost of emission allowances of the “advanced” economies equal to $140 in 2040 in 2019 currency per ton. IEA price assumptions for hydrocarbons are substantially in line with those adopted by Eni, while the cost of CO2 is significantly higher. This stress test indicates a loss in the value-in-use of the Exploration & Production sector equal to 11% with respect to the base case, assuming non-deductibility or non-recoverability for cost oil purposes of the CO2 charge (-5%). These sensitivity analyses do not, however, represent management's best estimate of any impairment losses that might be recognized as they do not fully incorporate the consequential changes that management could implement such as changes to business plans, cost reduction, development reshaping, review of reserves and production volumes.

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15 Investments

Equity-accounted investments

	2020								2019
(€ million)	Investments in unconsolidated entities controlled by Eni		Joint ventures		Associates		Total		Investments in unconsolidated entities controlled by Eni		Joint ventures		Associates		Total
Carrying amount – beginning of the year		86		4,592		4,357		9,035		95		5,497		1,452		7,044
Changes in accounting policies (IAS 28)												22				22
Carrying amount restated – beginning of the year		86		4,592		4,357		9,035		95		5,519		1,452		7,066
Additions and subscriptions		2		75		198		275		6		76		2,910		2,992
Divestments and reimbursements				(3)		(1)		(4)		(5)				(17)		(22)
Share of profit of equity-accounted investments		3		21		14		38		6		80		75		161
Share of loss of equity-accounted investments		(2)		(1,399)		(332)		(1,733)		(10)		(157)		(17)		(184)
Deduction for dividends		(5)		(296)		(13)		(314)		(4)		(1,073)		(61)		(1,138)
Change in the scope of consolidation		3		30		1		34		1						1
Currency translation differences		(4)		(254)		(345)		(603)		2		67		17		86
Other changes		(3)		66		(42)		21		(5)		80		(2)		73
Carrying amount – end of the year		80		2,832		3,837		6,749		86		4,592		4,357		9,035

Acquisitions and share capital increases mainly related: (i) for €89 million to the acquisition of a 49% stake in Novis Renewables Holdings Llc and a 50% stake in Novis Renewables Llc and the subsequent capital increase of both companies as part of the partnership with Falck Renewables for the joint development of renewable energy projects in the United States; (ii) for €72 million to the acquisition of a 40% stake of Finproject SpA, a company operating in the compounding sector and in the production of ultralight fabrics, businesses more resilient to the volatility of the chemicals market; (iii) for €38 million to a capital contribution made to Lotte Versalis Elastomers Co Ltd, a joint venture operating in the manufacturing of elastomers in South Korea.

The accounting under the equity method included losses related to: (i) Vår Energi AS for €918 million due to impairment losses recorded at the CGUs of the investee due to a revised long-term outlook for hydrocarbons prices and changes in production profiles; (ii) Abu Dhabi Oil Refining Co (Takreer) for €275 million due to a weaker refining scenario and the recognition of a significant loss in the alignment of the book values of inventories at their net realizable values; (iii) Saipem SpA for €354 million due to a weaker scenario, which impacted the investment decisions of oil companies together with the curtailments of expenditures made during the downturn driving, lower demand for oil and gas services as well as the recognition of impairment losses in particular in the Offshore Drilling CGU.

Share of losses of equity-accounted investments included a loss of €46 million accounted at the joint venture Cardón IV SA (Eni’s interest 50%) which is operating the Perla gas field in Venezuela, affected by the slowdown in the gas supplies to the buyer PDVSA due to a deteriorated operating environment.

Deduction for dividends related for €274 million to Vår Energi AS.

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Net carrying amount related to the following companies:

	December 31, 2020				December 31, 2019
(€ million)	Net carrying amount		% of the investment		Net carrying amount		% of the investment
Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd		24		100.00		30		100.00
Other		56				56
		80				86
Joint ventures
Vår Energi AS		1,144		69.85		2,518		69.60
Saipem SpA		908		31.08		1,250		30.99
Unión Fenosa Gas SA		242		50.00		326		50.00
Cardón IV SA		199		50.00		148		50.00
Gas Distribution Company of Thessaloniki – Thessaly SA		140		49.00		139		49.00
Lotte Versalis Elastomers Co Ltd		51		50.00		74		50.00
PetroJunín SA		50		40.00		53		40.00
Società Oleodotti Meridionali – SOM SpA		32		70.00
AET – Raffineriebeteiligungsgesellschaft mbH		17		33.33		35		33.33
Other		49				49
		2,832				4,592
Associates
Abu Dhabi Oil Refining Co (Takreer)		2,335		20.00		2,829		20.00
Angola LNG Ltd		1,039		13.60		1,159		13.60
Coral FLNG SA		138		25.00		102		25.00
Finproject SpA		73		40.00
Novis Renewables Holdings Llc		65		49.00
United Gas Derivatives Co		58		33.33		69		33.33
Novamont SpA						71		25.00
Other		129				127
		3,837				4,357
		6,749				9,035

Results of equity-accounted investments by segment are disclosed in note 35 — Segment information and information by geographical area.

The carrying amounts of equity-accounted investments included differences between the purchase price of acquired interests and their underlying book value of net assets amounting to €44 million relating to Finproject SpA. This surplus was driven by the long-term profitability outlook of the acquired company at the time of the acquisition.

As of December 31, 2020, the market value of the investments listed in regulated stock markets was as follows:

	Saipem SpA
Number of shares held		308,767,968
% of the investment		31.08
Share price (€)		2.205
Market value (€ million)		681
Book value (€ million)		908

As of December 31, 2020, the fair value of Saipem was 25% lower than the book value in Eni’s financial statements. Due to this impairment indicator, given the volatility of the stock and the significant spending cuts implemented by the oil companies in the short and medium term in response to the collapse in hydrocarbons prices, management performed an impairment test of the book value of the investment based on an internal estimation of the value in use of the investment, which confirmed the carrying amount.

Additional information is included in note 37 — Other information about investments.

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Other investments

(€ million)	2020		2019
Carrying amount – beginning of the year		929		919
Additions and subscriptions		8		11
Change in the fair value		24		(3)
Divestments and reimbursements		(12)		(12)
Currency translation differences		(61)		15
Other changes		69		(1)
Carrying amount – end of the year		957		929

The fair value of the main non-controlling interests in non-listed investees on regulated markets, classified within level 3 of the fair value hierarchy, was estimated based on a methodology that combines future expected earnings and the sum-of-the-parts methodology (so-called residual income approach) and takes into account, inter alia, the following inputs: (i) expected results, 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 evaluation.

Dividend income from these investments is disclosed in note 31 — Income (expense) from investments.

The investment book value as of December 31, 2020 primarily related to Nigeria LNG Ltd for €579 million (€657 million at December 31, 2019), Saudi European Petrochemical Co “IBN ZAHR” for €115 million (€146 million at December 31, 2019) and Novamont SpA for €77 million.

16 Other financial assets

	December 31, 2020				December 31, 2019
(€ million)	Current		Non-current		Current		Non-current
Long-term financing receivables held for operating purposes		29		953		60		1,119
Short-term financing receivables held for operating purposes		22				37
		51		953		97		1,119
Financing receivables held for non-operating purposes		203				287
		254		953		384		1,119
Securities held for operating purposes				55				55
		254		1,008		384		1,174

Changes in allowance for doubtful accounts were as follows:

(€ million)	2020		2019
Carrying amount at the beginning of the year		379		430
Additions		7		11
Deductions		(7)		(88)
Currency translation differences		(26)		7
Other changes		(1)		19
Carrying amount at the end of the year		352		379

Financing receivables held for operating purposes related principally to funds provided to joint ventures and associates in the Exploration & Production segment (€883 million) to execute capital projects of interest to Eni. These receivables are long-term interests in the initiatives funded. The greatest exposure is towards the joint venture Cardón IV SA (Eni’s interest 50%) in Venezuela, which is currently operating the Perla offshore gas field, for €383 million (€563 million at December 31, 2019).

Financing receivables held for operating purposes due beyond five years amounted to €771 million (€1,018 million at December 31, 2019).

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The fair value of non-current financing receivables held for operating purposes of €953 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from -0.5% to 1.4% (-0.3% and 2.0% at December 31, 2019).

In addition to the expected credit loss model, the recoverability of the financial loan granted to the joint venture Cardón IV SA was assessed on the basis of the recoverability of the investment made by the JV for the development of the Perla field corresponding to the future cash flows of the project adjusted to price possible difficulties in converting future gas sales into cash, essentially assuming a deferral in the timing of revenues collection.

The recoverability of other long-term financial assets was assessed by considering the expected probability 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 related to bank deposits with the purpose to invest cash surpluses and restricted deposits in escrow to guarantee transactions on derivative contracts.

Financing receivables held for operating purposes were denominated in euro and U.S. dollar for €178 million and €1,024 million, respectively.

Securities held for operating purposes related to listed bonds issued by sovereign states.

Securities for €20 million (same amount as of December 31, 2019) 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

from 0.35 to 4.75

from 2021 to 2030

Baa3

BBB

Others (*)

from 0.05 to 0.20

from 2021 to 2025

from Aa3 to Baa1

from AA to A

Floating rate bonds

Italy

from 2022 to 2025

Baa3

BBB

Others

2022

Baa3

BBB

Total sovereign
states

(*)

Amounts included herein are lower than €10 million.

All securities have maturity within five years.

The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in note 36 — Transactions with related parties.

17 Trade and other payables

(€ million)	December 31, 2020		December 31, 2019
Trade payables		8,679		10,480
Down payments and advances from joint ventures in exploration & production activities		417		401
Payables for purchase of non-current assets		1,393		2,276
Payables due to partners in exploration & production activities		1,120		1,236
Other payables		1,327		1,152
		12,936		15,545

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The decrease in trade payables of €1,801 million was mainly due to lower prices of hydrocarbons.

Other payables included: (i) the amounts to be paid due to the triggering of the take-or-pay clause of the long-term supply contracts for €376 million (€148 million at 31 December 2019); (ii) payroll payables for €255 million (€215 million at December 31, 2019); (iii) payables for social security contributions for €92 million (same amount as of December 31, 2019).

Trade and other payables were denominated in euro for €5,384 million and in U.S. dollar for €6,243 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.

18 Finance debts

	December 31, 2020								December 31, 2019
(€ million)	Short-term debt		Current portion of long-term debt		Long-term debt		Total		Short-term debt		Current portion of long-term debt		Long-term debt		Total
Banks		337		759		3,193		4,289		187		504		2,341		3,032
Ordinary bonds				1,140		18,280		19,420				2,642		16,137		18,779
Convertible bonds						396		396						393		393
Commercial papers		2,233						2,233		1,778						1,778
Other financial institutions		312		10		26		348		487		10		39		536
		2,882		1,909		21,895		26,686		2,452		3,156		18,910		24,518

Finance debts increased by €2,168 million due to new issuance, net of repayments of €3,115 million, partially offset by currency translation differences relating to foreign subsidiaries and debts denominated in foreign currency recorded by euro-reporting subsidiaries for €876 million.

Commercial papers were issued by the Group’s financial subsidiaries.

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, 2020, debts subjected to restrictive covenants amounted to €1,051 million (€1,243 million at December 31, 2019). Eni was in compliance with those covenants.

Ordinary bonds consisted of bonds issued within the Euro Medium Term Notes Program for a total of €16,356 million and other bonds for a total of €3,064 million.

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The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2020:

(€ million)	Amount		Discount on bond issue and accrued expense		Total		Currency		Maturity				Rate %
(€ million)	Amount		Discount on bond issue and accrued expense		Total		Currency		from		to		from		to
Issuing entity
Euro Medium Term Notes
Eni SpA		1,200		16		1,216		EUR				2025				3.750
Eni SpA		1,000		28		1,028		EUR				2029				3.625
Eni SpA		1,000		12		1,012		EUR				2023				3.250
Eni SpA		1,000		10		1,010		EUR				2031				2.000
Eni SpA		1,000		9		1,009		EUR				2026				1.500
Eni SpA		1,000		2		1,002		EUR				2030				0.625
Eni SpA		1,000				1,000		EUR				2026				1.250
Eni SpA		900		(2)		898		EUR				2024				0.625
Eni SpA		800		2		802		EUR				2021				2.625
Eni SpA		800		1		801		EUR				2028				1.625
Eni SpA		750		10		760		EUR				2024				1.750
Eni SpA		750		6		756		EUR				2027				1.500
Eni SpA		750		(4)		746		EUR				2034				1.000
Eni SpA		700		2		702		EUR				2022				0.750
Eni SpA		650		3		653		EUR				2025				1.000
Eni SpA		600		(4)		596		EUR				2028				1.125
Eni Finance International SA		1,427		(3)		1,424		USD		2026		2027				variable
Eni Finance International SA		795		6		801		EUR		2025		2043		1.275		5.441
Eni Finance International SA		111		5		116		GBP				2021				4.750
Eni Finance International SA		24				24		YEN				2021				1.955
		16,257		99		16,356
Other bonds
Eni SpA		815		5		820		USD				2023				4.000
Eni SpA		815		3		818		USD				2028				4.750
Eni SpA		815		(1)		814		USD				2029				4.250
Eni SpA		285		1		286		USD				2040				5.700
Eni USA Inc		326				326		USD				2027				7.300
		3,056		8		3,064
		19,313		107		19,420

As of December 31, 2020, ordinary bonds maturing within 18 months amounted to €1,644 million. During 2020, new bonds issued amounted to €3,514 million.

The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, 2020:

(€ million)

Amount

Discount on
bond issue
and accrued
expense

Total

Currency

Maturity

Rate %

Eni SpA

400

(4)

396

EUR

2022

0.000

This is a non-dilutive equity-linked bond, which provides for a redemption value linked to the market price of Eni’s shares. The bondholders can exercise their conversion rights at certain expiry dates and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, to hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The bond conversion price is equal €17.62 and includes a 35% premium with respect to the Eni’s share reference price at the date of issuance. The convertible bond is measured at amortized cost. The conversion option, embedded in the financial instrument issued, and the call option on Eni’s shares acquired are valued at fair value with effects recognized through profit and loss.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €16.3 billion were drawn as of December 31, 2020.

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The following table provides a breakdown by currency of finance debt and the related weighted average interest rates:

	December 31, 2020								December 31, 2019
	Short term debt (€ million)		Average rate (%)		Long term debt and current portion of long term debt (€ million)		Average rate (%)		Short term debt (€ million)		Average rate (%)		Long term debt and current portion of long term debt (€ million)		Average rate (%)
Euro		1,004				19,142		1.7		464		0.2		16,526		2.1
U.S. dollar		1,870		1.1		4,522		4.6		1,981		2.3		5,392		4.6
Other currencies		8		(0.5)		140		4.3		7		(0.7)		148		4.3
		2,882				23,804				2,452				22,066

As of December 31, 2020, Eni retained undrawn uncommitted short-term borrowing facilities amounting to €7,183 million (€13,299 million at December 31, 2019) and undrawn committed borrowing facilities of €5,295 million, of which €4,750 million due beyond 12 months (€4,667 million at December 31, 2019, of which €4,217 million due beyond 12 months). Those facilities bore interest rates reflecting prevailing conditions in the marketplace.

As of December 31, 2020, 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 31, 2020		December 31, 2019
(€ million)
Ordinary bonds		22,429		19,173
Convertible bonds		497		402
Banks		4,008		2,904
Other financial institutions		36		49
		26,970		22,528

Fair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from -0.5% to 1.4% (-0.3% and 2.0% at December 31, 2019).

Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.

Changes in liabilities arising from financing activities

(€ million)	Long-term debt and current portion of long-term debt		Short-term debt		Long-term and current portion of long-term lease liabilities		Total
Carrying amount at December 31, 2019		22,066		2,452		5,648		30,166
Cash flows		2,178		937		(869)		2,246
Currency translation differences		(348)		(528)		(333)		(1,209)
Other non-monetary changes		(92)		21		572		501
Carrying amount at December 31, 2020		23,804		2,882		5,018		31,704

Other non-monetary changes include €808 million of lease liabilities assumptions.

Lease liabilities are described in note 12 — Right-of-use assets and lease liabilities.

Transactions with related parties are described in note 36 — Transactions with related parties

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19 Information on net borrowings

In assessing its capital structure, Eni uses net borrowings before the accounting effects of IFRS 16 (lease obligations) , 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 and cash equivalents, held-for-trading securities and certain highly liquid investments not related to operations including, among others, non-operating financing receivables. Held-for-trading securities are part of a strategic reserve of liquidity that management has established by reinvesting proceeds from the Group disposal plans and is intended to provide a certain degree of financial flexibility in case of a prolonged price downturn, tight financial markets or in view of other Company’s purposes. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

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 by which Eni’s operating assets are financed.

	December 31, 2020						December 31, 2019
(€ million)	Current		Non-current		Total		Current		Non-current		Total
A. Cash and cash equivalents		9,413				9,413		5,994				5,994
B. Financial assets held for trading		5,502				5,502		6,760				6,760
C Liquidity (A+B)		14,915				14,915		12,754				12,754
D. Financing receivables		203				203		287				287
E. Short-term debt towards banks		337				337		187				187
F. Long-term debt towards banks		759		3,193		3,952		504		2,341		2,845
G. Bonds		1,140		18,676		19,816		2,642		16,530		19,172
H. Short-term financial debt towards related parties		52				52		46				46
I. Other short-term financial liabilities		2,493				2,493		2,219				2,219
J. Other long-term financial liabilities		10		26		36		10		39		49
K. Total borrowings before lease liabilities (E+F+G+H+I+J)		4,791		21,895		26,686		5,608		18,910		24,518
L. Net borrowings before lease liabilities (K-C-D)		(10,327)		21,895		11,568		(7,433)		18,910		11,477
M. Lease liabilities		795		4,057		4,852		884		4,751		5,635
N. Lease liabilities towards related parties		54		112		166		5		8		13
O. Total borrowings including lease liabilities (K+M+N)		5,640		26,064		31,704		6,497		23,669		30,166
P. Net borrowings including lease liabilities (O-C-D)		(9,478)		26,064		16,586		(6,544)		23,669		17,125

Cash and cash equivalent are disclosed in note 5 — Cash and cash equivalent.

Financial assets held for trading are disclosed in note 6 — Financial assets held for trading.

Financing receivables are disclosed in note 16 — Other financial assets.

Finance debts are disclosed in note 18 — Finance debts.

Lease liabilities related for €1,652 million (€1,976 million at December 31, 2019) 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 is reported in note 12 — Right-of-use assets and lease liabilities.

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20 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 cover		Provisions for redundancy incentives		Provisions for disposal and restructuring		Other		Total
Carrying amount at December 31, 2019		8,936		2,602		850		199		333		188		113		70		46		769		14,106
New or increased provisions				168		172		61		160		44				1		2		193		801
Initial recognition and changes in estimates		955																				955
Accretion discount		190		(2)		1														1		190
Reversal of utilized provisions		(252)		(296)		(526)		(30)		(237)						(7)		(14)		(266)		(1,628)
Reversal of unutilized provisions		(3)		(183)		(96)		(53)				(6)		(9)		(11)		(4)		(38)		(403)
Currency translation differences		(469)				(31)		(8)				(4)		(1)						(9)		(522)
Other changes		5		(26)		15		1		2		(24)		(8)				(1)		(25)		(61)
Carrying amount at December 31, 2020		9,362		2,263		385		170		258		198		95		53		29		625		13,438

Provisions for site restoration, abandonment and social projects include 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 restoration for €8,454 million. Initial recognitions and changes in estimates of €955 million were driven by a decrease in the discount rates and the estimate of the costs for social projects to be incurred following the commitments between Eni SpA and the Basilicata region in relation to the oil development program in the Val d’Agri concession area (€439 million). The unwinding of discount recognized through profit and loss for €190 million was determined based on discount rates ranging from -0.2% to 3.7% (from -0.1% to 6.1% at December 31, 2019). Main expenditures associated with decommissioning operations are expected to be incurred over a fifty-year period.

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 the 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. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to performing certain cleaning-up and restoration projects and a reliable cost estimation is available. At December 31, 2020, environmental provision primarily related to Eni Rewind SpA for €1,647 million and to the Refining & Marketing business line for €359 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. These provisions represent the Company’s best estimate of the expected and probable liabilities associated with ongoing litigation and related to the Exploration & Production segment for €250 million. Reversals of utilized provisions related for €515 million to the Exploration & Production segment in relation to the settlement of contractual disputes.

Provisions for uncertain taxes 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 were in respect of the Exploration & Production segment for €139 million.

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 was recorded receivables of €116 million recognized towards insurance companies for reinsurance contracts.

Provisions for losses on investments included provisions relating to investments whose loss exceeds the equity and primarily related to Industria Siciliana Acido Fosforico — ISAF — SpA (in liquidation) for €146 million.

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Provisions for the OIL mutual insurance scheme included the estimated future increase of insurance premiums which will be charged to Eni in the next five years and that were accrued at the reporting date because of the effective accident rate occurred in past reporting periods.

Provisions for redundancy incentives were recognized mainly due to a restructuring program involving the Italian personnel related to past reporting periods.

21 Provisions for employee benefits

(€ million)	December 31, 2020		December 31, 2019
Italian defined benefit plans		258		269
Foreign defined benefit plans		493		412
FISDE, foreign medical plans and other		182		177
Defined benefit plans		933		858
Other benefit plans		268		278
Provision for employee benefits		1,201		1,136

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 €128 million, the isopensione plans (a post retirement benefit plan applicable to a specific category of employees) of Eni gas e luce SpA for €97 million, jubilee awards for €28 million and other long-term plans for €15 million.

Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

	2020												2019
(€ million)	Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Defined benefit plans		Other benefit plans		Total		Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Defined benefit plans		Other benefit plans		Total
Present value of benefit liabilities at beginning of year		269		1,044		177		1,490		278		1,768		275		925		148		1,348		309		1,657
Current cost				23		3		26		50		76				19		2		21		55		76
Interest cost		2		27		2		31		1		32		4		37		3		44		1		45
Remeasurements:		5		48		13		66		4		70		5		41		24		70		1		71
- actuarial (gains) losses due to changes in demographic assumptions		(3)		(10)		2		(11)		2		(9)
- actuarial (gains) losses due to changes in financial assumptions		9		71		13		93		5		98		7		50		3		60		1		61
- experience (gains) losses		(1)		(13)		(2)		(16)		(3)		(19)		(2)		(9)		21		10				10
Past service cost and (gains) losses settlements				(2)				(2)		20		18				1		8		9		(2)		7
Plan contributions:				1				1				1				1				1				1
- employee contributions				1				1				1				1				1				1
Benefits paid		(20)		(33)		(9)		(62)		(63)		(125)		(15)		(28)		(9)		(52)		(88)		(140)
Currency translation differences and other changes		2		32		(4)		30		(22)		8				48		1		49		2		51
Present value of benefit liabilities at end of year (a)		258		1,140		182		1,580		268		1,848		269		1,044		177		1,490		278		1,768
Plan assets at beginning of year				632				632				632				545				545				545
Interest income				15				15				15				20				20				20
Return on plan assets				51				51				51				23				23				23
Past service cost and (gains) losses settlements				(3)				(3)				(3)
Plan contributions:				15				15				15				14				14				14
- employee contributions				1				1				1				1				1				1
- employer contributions				14				14				14				13				13				13
Benefits paid				(21)				(21)				(21)				(19)				(19)				(19)
Currency translation differences and other changes				(41)				(41)				(41)				49				49				49
Plan assets at end of year (b)				648				648				648				632				632				632
Asset ceiling at beginning of year																5				5				5
Change in asset ceiling				1				1				1				(5)				(5)				(5)
Asset ceiling at end of year (c)				1				1				1
Net liability recognized at end of year (a-b+c)		258		493		182		933		268		1,201		269		412		177		858		278		1,136

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Employee benefit plans included the liability attributable to partners operating in exploration and production activities of €268 million (€175 million at December 31, 2019). Eni recorded a receivable for an amount equivalent to such liability.

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
2020
Current cost				23		3		26		50		76
Past service cost and (gains) losses on settlements				1				1		20		21
Interest cost (income), net:
- interest cost on liabilities		2		27		2		31		1		32
- interest income on plan assets				(15)				(15)				(15)
Total interest cost (income), net		2		12		2		16		1		17
- of which recognized in “Payroll and related cost”										1		1
- of which recognized in “Financial income (expense)”		2		12		2		16				16
Remeasurements for long-term plans										4		4
Total		2		36		5		43		75		118
- of which recognized in “Payroll and related cost”				24		3		27		75		102
- of which recognized in “Financial income (expense)”		2		12		2		16				16
2019
Current cost				19		2		21		55		76
Past service cost and (gains) losses on settlements				1		8		9		(2)		7
Interest cost (income), net:
- interest cost on liabilities		4		37		3		44		1		45
- interest income on plan assets				(20)				(20)				(20)
Total interest cost (income), net		4		17		3		24		1		25
- of which recognized in “Payroll and related cost”										1		1
- of which recognized in “Financial income (expense)”		4		17		3		24				24
Remeasurements for long-term plans										1		1
Total		4		37		13		54		55		109
- of which recognized in “Payroll and related cost”				20		10		30		55		85
- of which recognized in “Financial income (expense)”		4		17		3		24				24

Costs of defined benefit plans recognized in other comprehensive income consisted of the following:

	2020								2019
(€ 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
Remeasurements
Actuarial (gains)/losses due to changes in demographic assumptions		(3)		(10)		2		(11)
Actuarial (gains)/losses due to changes in financial assumptions		9		71		13		93		7		50		3		60
Experience (gains) losses		(1)		(13)		(2)		(16)		(2)		(9)		21		10
Return on plan assets				(51)				(51)				(23)				(23)
Change in asset ceiling				1				1				(5)				(5)
		5		(2)		13		16		5		13		24		42

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Plan assets consisted of the following:

(€ million)	Cash and cash equivalents		Equity securities		Debt securities		Real estate		Derivatives		Investment funds		Assets held by insurance company		Other		Total
December 31, 2020
Plan assets with a quoted market price		117		38		297		8		2		76		20		87		645
Plan assets without a quoted market price														3				3
		117		38		297		8		2		76		23		87		648
December 31, 2019
Plan assets with a quoted market price		32		39		388		7		2		79		17		65		629
Plan assets without a quoted market price														3				3
		32		39		388		7		2		79		20		65		632

The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2021 consisted of the following:

		Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Other benefit plans
2020
Discount rate	(%)		0.3		0.1-14.7		0.3		0.0-0.3
Rate of compensation increase	(%)		1.8		1.3-12.5
Rate of price inflation	(%)		0.8		0.8-12.2		0.8		0.8
Life expectations on retirement at age 65	(years)				13-26		24
2019
Discount rate	(%)		0.7		0.0-13.7		0.7		0.0-0.7
Rate of compensation increase	(%)		1.7		1.3-12.5
Rate of price inflation	(%)		0.7		0.8-11.3		0.7		0.7
Life expectations on retirement at age 65	(years)				13-25		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
2020
Discount rate	(%)		0.4-0.8		0.1-1.4		2.6-14.7		6.4-9.8		0.1-14.7
Rate of compensation increase	(%)		1.3-3.0		2.5-3.6		2.0-12.5		5.0-9.8		1.3-12.5
Rate of price inflation	(%)		1.3-1.9		0.8-3.1		2.6-12.2		3.0-5.0		0.8-12.2
Life expectations on retirement at age 65	(years)		21-22		23-26		13-17				13-26
2019
Discount rate	(%)		0.8-1.0		0.0-2.0		2.6-13.7		7.3-11.3		0.0-13.7
Rate of compensation increase	(%)		1.3-3.0		2.5-3.6		2.0-12.5		10.0-11.3		1.3-12.5
Rate of price inflation	(%)		1.3-2.0		0.8-3.1		2.6-11.3		3.3-5.0		0.8-11.3
Life expectations on retirement at age 65	(years)		21-22		24-25		13-17				13-25

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The effects of a possible change in the main actuarial assumptions at the end of the year are listed below:

	Discount rate				Rate of price inflation		Rate of increases in pensionable salaries		Healthcare cost trend rate		Rate of increases to pensions in payment
(€ million)	0.5% Increase		0.5% Decrease		0.5% Increase		0.5% Increase		0.5% Increase		0.5% Increase
December 31, 2020
Italian defined benefit plans		(10)		6		7
Foreign defined benefit plans		(84)		92		47		25				67
FISDE, foreign medical plans and other		(10)		7						11
Other benefit plans		(3)		1		1
December 31, 2019
Italian defined benefit plans		(12)		13		8
Foreign defined benefit plans		(67)		77		31		18				34
FISDE, foreign medical plans and other		(9)		10						10
Other benefit plans		(4)		1		1

The sensitivity analysis was performed based on the results for each plan through assessments calculated considering modified parameters.

The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €132 million, of which €61 million related to defined benefit plans.

The following is an analysis by maturity date of the liabilities for employee benefit plans and their relative weighted average duration:

(€ million)	Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Other benefit plans
December 31, 2020
2021		12		44		8		71
2022		13		42		7		66
2023		17		50		7		63
2024		20		63		7		16
2025		21		67		7		12
2026 and thereafter		175		227		146		40
Weighted average duration (years)		8.2		19.1		13.7		2.8
December 31, 2019
2020		17		33		9		73
2021		16		35		8		68
2022		12		32		7		61
2023		10		39		7		17
2024		15		49		7		14
2025 and thereafter		199		224		139		45
Weighted average duration (years)		9.4		18.1		13.3		3.0

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22 Deferred tax assets and liabilities

(€ million)	December 31, 2020		December 31, 2019
Deferred tax liabilities before offsetting		8,581		9,583
Deferred tax assets available for offset		(3,057)		(4,663)
Deferred tax liabilities		5,524		4,920
Deferred tax assets before offsetting (net of accumulated write-down provisions)		7,166		9,023
Deferred tax liabilities available for offset		(3,057)		(4,663)
Deferred tax assets		4,109		4,360

The most significant temporary differences giving rise to net deferred tax assets and liabilities are disclosed below:

(€ million)	Carrying amount at December 31, 2020		Carrying amount at December 31, 2019
Deferred tax liabilities
Accelerated tax depreciation		6,171		6,796
Leasing		1,089		1,375
Difference between the fair value and the carrying amount of assets acquired		415		617
Site restoration and abandonment (tangible assets)		199		126
Application of the weighted average cost method in evaluation of inventories		56		97
Other		651		572
		8,581		9,583
Deferred tax assets, gross
Carry-forward tax losses		(6,983)		(6,065)
Site restoration and abandonment (provisions for contingencies)		(2,211)		(2,242)
Timing differences on depreciation and amortization		(2,206)		(2,022)
Accruals for impairment losses and provisions for contingencies		(1,371)		(1,513)
Impairment losses		(1,213)		(946)
Leasing		(1,113)		(1,385)
Employee benefits		(213)		(209)
Over/Under lifting		(211)		(525)
Unrealized intercompany profits		(117)		(120)
Other		(593)		(740)
		(16,231)		(15,767)
Accumulated write-downs of deferred tax assets		9,065		6,744
Deferred tax assets, net		(7,166)		(9,023)

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The following table summarizes the changes in deferred tax liabilities and assets:

(€ million)	Deferred tax liabilities, gross		Deferred tax assets, gross		Accumulated write-downs of deferred tax assets		Deferred tax assets, net of impairments
Carrying amount at December 31, 2019		9,583		(15,767)		6,744		(9,023)
Additions		960		(2,649)		2,638		(11)
Deductions		(1,326)		1,357		(130)		1,227
Currency translation differences		(725)		742		(192)		550
Other changes		89		86		5		91
Carrying amount at December 31, 2020		8,581		(16,231)		9,065		(7,166)
Carrying amount at December 31, 2018		7,956		(13,356)		5,741		(7,615)
Changes in accounting policies (IFRS 16)		1,470		(1,470)				(1,470)
Carrying amount at January 1, 2019		9,426		(14,826)		5,741		(9,085)
Additions		1,265		(2,091)		1,161		(930)
Deductions		(1,205)		1,407		(174)		1,233
Currency translation differences		194		(182)		34		(148)
Other changes		(97)		(75)		(18)		(93)
Carrying amount at December 31, 2019		9,583		(15,767)		6,744		(9,023)

Carry-forward tax losses amounted to €23,325 million, of which €17,323 million can be carried forward indefinitely. Carry-forward tax losses were €13,153 million and €10,172 million at Italian subsidiaries and foreign subsidiaries, respectively. Deferred tax assets recognized on these losses amounted to €3,734 million and €3,249 million, respectively.

Italian taxation law allows the carry-forward of tax losses indefinitely. Foreign taxation 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 31.9%.

Accumulated write-downs of deferred tax assets related to Italian companies for €7,090 million and non-Italian companies for €1,975 million.

Taxes are also described in note 32 — Income taxes.

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Eni is exposed to the 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 related to derivatives that did not meet the formal criteria to be designated as hedges under IFRS.

Fair values of trading derivatives 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 related to commodity hedges were entered 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 25 — Equity. Information on hedged risks and hedging policies is disclosed in note 27 — Guarantees, commitments and risks — Risk factors.

In 2020, the exposure to the exchange rate risk deriving from securities denominated in US dollars included in the strategic liquidity portfolio amounting to €1,335 million was hedged by using, in a fair value hedge relationship, negative exchange differences for €120 million resulting on a portion of bonds denominated in US dollars amounting to €1,546 million.

Options embedded in convertible bonds relate to equity-linked cash settled. More information is disclosed in note 18 — Finance debts.

The offsetting of financial derivatives related to Eni Trading & Shipping.

During 2020, there were no transfers between the different hierarchy levels of fair value.

Hedging derivative instruments are disclosed below:

	December 31, 2020						December 31, 2019
(€ 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		821		(438)				2,179		(1,357)		(2)
- Future		541		158		(1)		1,245		(61)
		1,362		(280)		(1)		3,424		(1,418)		(2)

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The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge is provided below:

	December 31, 2020						December 31, 2019
(€ 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		284		(7)		(941)		1,444		(656)		(739)
		284		(7)		(941)		1,444		(656)		(739)

More information is reported in note 27 — 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)	2020		2019		2018
Net income (loss) on cash flow hedging derivatives		(1)		(2)
Net income (loss) on other derivatives		(765)		289		129
		(766)		287		129

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)	2020		2019		2018
Derivatives on exchange rate		391		9		(329)
Derivatives on interest rate		(40)		(23)		22
		351		(14)		(307)

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.

24 Assets held for sale and liabilities directly associated with assets held for sale

As of December 31, 2020, assets held for sale related to sales of tangible assets for €44 million (€18 million at December 31, 2019).

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25 Equity

Equity attributable to equity holders of Eni

(€ million)	December 31, 2020		December 31, 2019
Share capital		4,005		4,005
Retained earnings		34,043		35,894
Cumulative currency translation differences		3,895		7,209
Other reserves and equity instruments:
- Perpetual subordinated bonds		3,000
- Legal reserve		959		959
- Reserve for treasury shares		581		981
- Reserve for OCI on cash flow hedging derivatives net of the tax effect		(5)		(465)
- Reserve for OCI on defined benefit plans net of tax effect		(165)		(173)
- Reserve for OCI on equity-accounted investments		92		60
- Reserve for OCI on other investments valued at fair value		36		12
- Other reserves		190		190
Treasury shares		(581)		(981)
Net profit (loss) for the year		(8,635)		148
		37,415		47,839

Share capital

As of December 31, 2020, the parent company’s issued share capital consisted of €4,005,358,876 (same amount as of December 31, 2019) represented by 3,605,594,848 ordinary shares without nominal value (3,634,185,330 at December 31, 2019).

On May 13, 2020, Eni’s Shareholders’ Meeting declared: (i) to distribute a dividend of €0.43 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2019 dividend of €0.86 per share, of which €0.43 per share paid as interim dividend. The balance was paid on May 20, 2020, to shareholders on the register on May 18, 2020, record date on May 19, 2020; (ii) to cancel 28,590,482 treasury shares without nominal value maintaining unchanged the share capital and reducing the related reserve for an amount of €399,999,994.58, equal to the carrying value of the shares cancelled.

Retained earnings

Retained earnings include the interim dividend distribution effect for 2020 amounting to €429 million corresponding to €0.12 per share, as resolved by the Board of Directors on September 15, 2020, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 23, 2020.

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

Eni issued two euro-denominated perpetual subordinated hybrid bonds for an aggregate nominal amount of €3 billion; issuing costs amounted to €25 million.

The hybrid bonds are governed by English law and are traded on the regulated market of the Luxembourg Stock Exchange.

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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 non-call hybrid notes with a re-offer price of 100% and an annual fixed coupon of 3.375% until the first reset date of October 13, 2029. As from such date, unless it has been redeemed in whole on or before the first reset date, which is the last day for the first optional redemption, the bond will bear interest per annum determined according to the relevant 5-year Euro Mid Swap rate plus an initial spread of 364.1 basis points, increased by additional 25 basis points as from October 13, 2034 and a subsequent increase of additional 75 basis points as from October 13, 2049.

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*
(€ million)	Gross reserve		Deferred tax liabilities		Net reserve		Gross reserve		Deferred tax liabilities		Net reserve		Reserve for OCI on equity-accounted investments		Reserve for OCI on investments valued at fair value
Reserve as of December 31, 2019		(656)		191		(465)		(190)		17		(173)		60		12
Changes of the year		(280)		81		(199)		(16)		25		9		32		24
Foreign currency translation differences								(6)		5		(1)
Reversal to inventories adjustments		(12)		3		(9)
Reclassification adjustments		941		(273)		668
Reserve as of December 31, 2020		(7)		2		(5)		(212)		47		(165)		92		36
Reserve as of December 31, 2018		(13)		4		(9)		(143)		13		(130)		66		15
Changes of the year		(1,418)		411		(1,007)		(49)		5		(44)		(6)		(3)
Foreign currency translation differences								(3)				(3)
Change in scope of consolidation								5		(1)		4
Reversal to inventories adjustments		36		(10)		26
Reclassification adjustments		739		(214)		525
Reserve as of December 31, 2019		(656)		191		(465)		(190)		17		(173)		60		12

OCI for defined benefit plans at December 31, 2020 includes €7 million relating to equity-accounted investments (€7 million at December 31, 2019)

Other reserves

Other reserves related to a reserve of €127 million representing the increase in equity attributable to Eni associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiaries.

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Treasury shares

A total of 33,045,197 of Eni’s ordinary shares (61,635,679 at December 31, 2019) were held in treasury for a total cost of €581 million (€981 million at December 31, 2019).

On May 13, 2020, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2020-2022 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.

Distributable reserves

As of December 31, 2020, equity attributable to Eni included distributable reserves of approximately €30 billion.

Reconciliation of net profit and equity attributable to Eni of the parent company Eni SpA to consolidated net profit and equity attributable to Eni

	Net profit				Shareholders’ equity
(€ million)	2020		2019		December 31, 2020		December 31, 2019
As recorded in Eni SpA’s Financial Statements		1,607		2,978		44,707		41,636
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company		(10,660)		(2,800)		(8,839)		5,211
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(6)		(6)		193		202
- adjustments to comply with Group accounting policies		264		(348)		2,086		1,424
- elimination of unrealized intercompany profits		88		(74)		(478)		(593)
- deferred taxation		79		405		(176)		20
		(8,628)		155		37,493		47,900
Non-controlling interest		(7)		(7)		(78)		(61)
As recorded in Consolidated Financial Statements		(8,635)		148		37,415		47,839

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26 Other information

Supplemental cash flow information

(€ million)	2020		2019		2018
Investment in consolidated subsidiaries and businesses
Current assets		15		1		44
Non-current assets		193		12		198
Net borrowings		(64)				11
Current and non-current liabilities		(17)		(6)		(47)
Net effect of investments		127		7		206
Fair value of investments held before the acquisition of control						(50)
Non-controlling interests		(15)		(2)
Gain on a bargain purchase						(8)
Purchase price		112		5		148
less:
Cash and cash equivalents		(3)				(29)
Consolidated subsidiaries and businesses net of cash and cash equivalent acquired		109		5		119
Disposal of consolidated subsidiaries and businesses
Current assets				77		328
Non-current assets				188		5,079
Net borrowings				11		785
Current and non-current liabilities				(57)		(3,470)
Net effect of disposals				219		2,722
Reclassification of foreign currency translation differences among other items of comprehensive income				(24)		113
Fair value of share capital held after the sale of control						(3,498)
Fair value valuation for business combination						889
Gain (loss) on disposal				16		13
Selling price				211		239
less:
Cash and cash equivalents				(24)		(286)
Consolidated subsidiaries and businesses net of cash and cash equivalent disposed of				187		(47)

Investments in 2020 related to the acquisition by Eni gas e luce SpA of a 70% controlling stake in Evolvere, a group operating in the business of distributed generation from renewable sources for €97 million, net of acquired cash of €3 million, and to the acquisition by Eni New Energy SpA of the whole capital of three companies holding authorization rights for the construction of three wind projects in Puglia for €12 million. The allocation of the purchase price of both business combinations is final.

Investments in 2019 concerned: (i) the acquisition of a 60% stake of SEA SpA, which supplies services and solutions for energy efficiency in the residential and industrial segments in Italy; (ii) the acquisition of the residual 32% interest in the joint operation Petroven Srl, which operates storage facilities of petroleum products.

Disposals in 2019 concerned the sale of 100% of the stake of Agip Oil Ecuador BV, which retains a service contract for the development of the Villano oil field.

Investments in 2018 concerned: (i) the acquisition of the business by Versalis SpA of the “bio” activities of the Mossi & Ghisolfi Group, related to development, industrialization, licensing of bio-chemical technologies and processes based on use of renewable sources for €75 million; (ii) the acquisition of the remaining 51% stake in the Gas Supply Company of Thessaloniki — Thessalia SA which distributes and sells gas in Greece for €24 million, net of cash acquired of €28 million; (iii) the acquisition of the company Mestni Plinovodi distribucija plina doo, which distributes and sells gas in Slovenia for €15 million, net of cash acquired for €1 million. The gain from bargain purchase, recognized in Other income and revenues, was due to the obtainable synergies from the greater ability to recover the investments made by the acquired company due to the combination of customer portfolios.

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Disposals in 2018 concerned: (i) the loss of control of Eni Norge AS resulting from the business combination with Point Resources AS, with the establishment of the equity-accounted joint venture Vår Energi AS (Eni’s interest 69.60%), that will develop the project portfolio of the combined entities. The operation entailed the change in scope of consolidation of €2,486 million of net assets, of which cash and cash equivalents for €258 million, the recognition of the investment in Vår Energi AS for €3,498 million and a fair value gain of €889 million, net of negative exchange rate differences of €123 million; (ii) the sale of 98.99% (entire stake owned) of Tigáz Zrt and Tigáz Dso (100% Tigáz Zrt) operating in the gas distribution business in Hungary to the MET Holding AG group for €145 million net of cash divested of €13 million; (iii) the sale by Lasmo Sanga Sanga of the business relating to a 26.25% stake (entire stake owned) in the PSA of the Sanga Sanga gas and condensates field for €33 million; (iv) the sale of 100% of Eni Croatia BV, which owns shares of gas projects in Croatia to INA-Industrija Nafte dd for €20 million, net of cash divested of €15 million; (v) the sale of 100% of Eni Trinidad and Tobago Ltd, which holds a share of a gas project in Trinidad and Tobago for €10 million.

27 Guarantees, commitments and risks

Guarantees

(€ million)	December 31, 2020		December 31, 2019
Consolidated subsidiaries		4,758		4,323
Unconsolidated subsidiaries		176		197
Joint ventures and associates		3,800		4,075
Others		150		267
		8,884		8,862

Guarantees issued on behalf of consolidated subsidiaries of €4,758 million (€4,323 million at December 31, 2019) primarily consisted of guarantees given to third parties relating to bid bonds and performance bonds for €3,209 million (€2,886 million at December 31, 2019). At December 31, 2019, the underlying commitment issued on behalf of consolidated subsidiaries covered by such guarantees was €4,520 million (€4,013 million at December 31, 2019).

Guarantees issued on behalf of joint ventures and associates of €3,800 million (€4,075 million at December 31, 2019) primarily consisted of: (i) unsecured guarantees and other guarantees for €1,533 million issued towards banks and other lending institutions in relation to loans and lines of credit received (€1,676 million at December 31, 2019), of which €1,304 million (€1,425 million at December 31, 2019) related to guarantees issued as part of the Coral development project offshore Mozambique with respect to the financing agreements of the project with Export Credit Agencies and banks; (ii) guarantees given to third parties relating to bid bonds and performance bonds for €1,544 million (€1,661 million at December 31, 2019), of which €1,079 million (€1,168 million at December 31, 2019) related to guarantees issued towards the contractors who are building a floating vessel for gas liquefaction and exportation (FLNG) as part of the Coral development project offshore Mozambique; (iii) an unsecured guarantee of €499 million (same amount as of December 31, 2019) given by Eni SpA on behalf of the participated Saipem joint-venture to Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project for the construction of the Milan-Bologna fast track railway by the CEPAV (Consorzio Eni per l’Alta Velocità) Uno; (iv) a guarantee issued in favor of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni’s interest 13.60%) to cover contractual commitments of paying re-gasification fees for €165 million (€181 million at December 31, 2019). At December 31, 2020, the underlying commitment issued on behalf of joint ventures and associates covered by such guarantees was €1,898 million (€2,109 million at December 31, 2019).

Guarantees issued on behalf of third parties of €150 million (€267 million at December 31, 2019) related for €145 million (€158 million at December 31, 2019) to 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. At December 31, 2020, the underlying commitment issued on behalf of third parties covered by such guarantees was €87 million (€80 million at December 31, 2019).

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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 Mozambique Rovuma Venture SpA 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 obligations of the guarantor towards the Government of Mozambique are unlimited (non-quantifiable commitments), whereas they provide a maximum liability of €1,223 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 operation Mozambico Rovuma Venture SpA, in proportion to their respective participating interest in Area 4.

Commitments and risks

(€ million)	December 31, 2020		December 31, 2019
Commitments		69,998		74,338
Risks		600		676
		70,598		75,014

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 €64,294 million (€65,374 million at December 31, 2019). The decrease of €1,080 million was primarily determined by negative exchange rate differences; (ii) a parent company guarantee of €3,260 million (€6,527 million at December 31, 2019) 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 set-up of ADNOC Global Trading Ltd dedicated to marketing petroleum products. The decrease of €3,267 million related to the extinction of the parent company guarantee, issued to guarantee the obligations under the Share Purchase Agreement, following the payment of the deferred consideration amounting to €73 million. 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 assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service Llc for the purchase of volumes of re-gasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031). The expected commitments were estimated at €1,672 million (€1,978 million at December 31, 2019) and have been included in off-balance sheet contractual commitments in the table “Future payments under contractual obligations” in the paragraph Liquidity risk. However, since the project has been abandoned by the partners, Eni does not expect to make any payment under those contractual obligations. In 2018, the contractual commitment signed in December 2007 between Eni USA Gas Marketing Llc and Gulf LNG Energy Llc (GLE) and Gulf LNG Pipeline Llc (GLP) for the purchase of long-term regasification and transport services (until 2031) amounting at December 31, 2017 to €948 million (undiscounted) ceased due to an arbitration ruling. The jurors established that the commitment was resolved by March 1, 2016 and recognized to the counterparty an equitable compensation of €324 million. Despite the ruling of the arbitration court invalidating the contract, GLE and GLP filed a claim with the Supreme Court of New York against Eni SpA demanding the enforcement of the parent company guarantee issued by Eni for the payment of the regasification fees until the original due date of the contract (2031) for a maximum amount of €757 million. Eni believes that the claims by GLE and GLP have no merit and is defending the action; (iv) the commitment to purchase of a 20% stake of the project relating to the Dogger Bank (A and B) wind facility in the North Sea for €451 million; (v) the commitment to purchase the remaining 60% stake of Finproject SpA, a company engaged in the compounding sector for €150 million; (vi) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest €108 million (€114 million at December 31, 2019) in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oilfields in Val d’Agri. The commitment has been included in the off-balance sheet contractual commitments in the following paragraph “Liquidity risk”.

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Risks relate to potential risks associated with: (i) contractual assurances given to acquirers of certain investments and businesses of Eni for €230 million (€248 million at December 31, 2019); (ii) assets of third parties under the custody of Eni for €370 million (€428 million at December 31, 2019).

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). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective due to a revision of the contractual terms. 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 €12 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.

Eni is liable for certain non-quantifiable risks related to contractual guarantees given to acquirers of certain Eni assets, including 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. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and cash flow.

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, in particular, the estimates of the probability of default and the loss given default have been updated to take into account the impacts of COVID-19 and its related effects on the economic context and the degree of solvency of Eni’s counterparts.

The crisis in energy consumption connected to lockdown measures adopted by the governments around the world to contain the spread of the pandemic and the consequent collapse in hydrocarbon prices have led to a significant contraction in Eni’s operating cash flows. Management has adopted all the necessary actions to protect the liquidity and the capital ratios of the Company by reducing costs and investments, by updating the shareholders’ remuneration policy and by recurring to capital market as described in the section Impact of COVID-19 pandemic of the Management Report, to which reference is made. As of December 31, 2020, the Company retains liquidity reserves that management deems enough to meet the financial obligations due in the next eighteen months.

No significant effects were reported on hedging transactions connected to the impacts of COVID-19 on the economic context.

Financial risks

Financial risks are managed in respect of 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 aim of the risk management, the valuation methodology, the structure of limits, the relationship model and the hedging and mitigation instruments.

Market risk

Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows.

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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, Eni Finance USA Inc and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni Corporate finance department, Eni Finance International SA and Eni Finance USA Inc manage subsidiaries’ financing requirements in and outside Italy and in the United States of America, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies different from commodities are managed by the parent company, while Eni Trading & Shipping SpA executes the negotiation of commodity derivatives over the market. Eni SpA and Eni Trading & Shipping SpA (also through its 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 Trading & Shipping 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 (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) 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 Trading & Shipping, its 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: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon; (ii) 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 (iii) 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 Trading & Shipping. 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 Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools the requests for negotiating commodity derivatives and executes 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.

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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. Changes in fair value of those derivatives are normally recognized through profit and loss, as they do not meet the formal criteria to be recognized as hedges. 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 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 plans. 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 plans, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to manage effectively 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

Eni’s results of operations are affected by changes in the prices of commodities. 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 those associated with the program for the production of proved and unproved oil&gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments to purchase natural gas, to the components related to the time horizon of the four-year plan and budget 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; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not for the purpose of delivery, both within the commodity and financial markets, with the aim to obtain a profit upon the occurrence of a favorable result in the market, in accordance with specific limits of authorized risk (VaR, stop loss). Origination activities are included in the proprietary trading exposures, if not connected to contractual or physical assets.

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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. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, 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 derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable economic results. Eni manages the commodity risk through the trading unit of Eni Trading & Shipping and the exposure to commodity prices through the Group’s finance departments by using derivatives traded on the organized markets MTF, OTF and 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 derivatives are valued at fair value based on market prices provided from specialized sources or, absent market prices, on the basis of 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) would affect the value of these instruments when valued at fair value. The setting up and maintenance of the liquidity reserve is 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 a coverage 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. Activities in terms of strategic liquidity management started in the second half of the year 2013 (Euro portfolio) and throughout the course of the year 2017 (U.S. dollar portfolio). In 2020, the Euro investment portfolio has maintained an average credit rating of A-/BBB+, whereas the USD investment portfolio has maintained an average credit rating of A+/A, both in line with the year 2019. The following tables show amounts in terms of VaR, recorded in 2020 (compared with 2019) relating to interest rate and exchange rate risks in the first section and commodity risk. Regarding the management of strategic liquidity, the sensitivity to changes of interest rate is expressed by values of “Dollar value per Basis Point” (DVBP).

(Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%)


	2020								2019
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end
Interest rate (a)		7.39		1.18		2.93		1.34		5.19		2.44		3.80		3.00
Exchange rate (a)		0.48		0.10		0.28		0.18		0.41		0.07		0.17		0.15

(a)

Value at risk deriving from interest and exchange rates exposures include the following finance departments: Eni Corporate Finance Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc.

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(Value at risk — Historic simulation method; holding period: 1 day; confidence level: 95%)


	2020								2019
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end
Commercial exposures – Management Portfolio(a)		16.10		3.02		8.50		3.02		23.03		7.74		11.22		9.11
Trading(b)		1.57		0.10		0.52		0.25		1.60		0.25		0.51		0.31

(a)

Refers to the Gas & LNG Marketing Power business line (risk exposure from Refining & Marketing business line and Global Gas & LNG Portfolio), Eni Trading & Shipping commercial portfolio, operating branches outside Italy pertaining to the Divisions and from October 2016 the Gas e Luce business line. For the Global Gas & LNG Portfolio business lines, following the approval of the Eni’s Board of Directors on December 12, 2013, 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 and EGL presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon.

(b)

Cross-commodity proprietary trading, both for commodity contracts and financial derivatives, refers to Eni Trading & Shipping SpA (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston).

(Sensitivity — Dollar value of 1 basis point — DVBP)


	2020								2019
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end
Strategic liquidity(a)		0.37		0.29		0.32		0.30		0.37		0.31		0.35		0.33

(a)

Management of strategic liquidity portfolio starting from July 2013.

(Sensitivity — Dollar value of 1 basis point — DVBP)


	2020								2019
($ million)	High		Low		Average		At year end		High		Low		Average		At year end
Strategic liquidity(a)		0.07		0.03		0.05		0.05		0.05		0.02		0.04		0.05

(a)

Management of strategic liquidity portfolio in $ 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 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. The credit worthiness of businesses and large clients 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

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premiums adopted for the purposes of the determination of the WACCs for the impairment of non-financial assets. Furthermore, 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 and Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and business units, only in the case of 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 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 liquidity 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 programs of the Company. The strategic liquidity reserve is employed in short-term marketable financial assets, favoring investments with very low risk profile.

At present, the Group believes to have access to 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 we believe we can activate at competitive costs through the credit system and the capital markets.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.3 billion were drawn as of December 31, 2020 (€13.9 billion by Eni SpA).

The Group has credit ratings of A- outlook negative 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 short-term 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 2020, the rating of Eni remained unchanged.

As part of the Euro Medium Term Notes program, in 2020 the Company issued bonds for €3.5 billion (€3.0 billion by Eni SpA).

In October 2020, Eni placed two euro-denominated perpetual subordinated hybrid bond issues for an aggregate nominal amount of €3 billion. These are perpetual instruments with an early repayment option in favor of the issuer and classified as equity items. The rating agencies assigned to the bonds the following ratings Baa3 / BBB / BBB (Moody’s / S&P / Fitch) and an “equity credit” of 50%.

As of December 31, 2020, Eni maintained short-term uncommitted unused borrowing facilities of €7,183 million. Committed unused borrowing facilities amounted to €5,295 million, of which €4,750 million due beyond 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.

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Expected payments for liabilities, trade and other payables

The tables below summarize the Group main contractual obligations for finance debt and lease liability repayments, including expected payments for interest charges and derivatives.

	Maturity year
(€ million)	2021		2022		2023		2024		2025		2026 and thereafter		Total
December 31, 2020
Non-current financial liabilities (including the current portion)		1,697		1,518		3,469		2,049		2,730		12,232		23,695
Current financial liabilities		2,882												2,882
Lease liabilities		815		593		503		442		413		2,218		4,984
Fair value of derivative instruments		1,609		26		13		50				73		1,771
		7,003		2,137		3,985		2,541		3,143		14,523		33,332
Interest on finance debt		502		473		461		387		360		1,164		3,347
Interest on lease liabilities		295		252		219		192		165		748		1,871
		797		725		680		579		525		1,912		5,218
Financial guarantees		1,072												1,072

	Maturity year
(€ million)	2020		2021		2022		2023		2024		2025 and thereafter		Total
December 31, 2019
Non-current financial liabilities (including the current portion)		2,908		1,704		1,259		2,743		1,785		11,521		21,920
Current financial liabilities		2,452												2,452
Lease liabilities		884		632		487		434		424		2,761		5,622
Fair value of derivative instruments		2,704		2		14						34		2,754
		8,948		2,338		1,760		3,177		2,209		14,316		32,748
Interest on finance debt		594		452		353		342		269		1,667		3,677
Interest on lease liabilities		341		302		263		233		206		1,015		2,360
		935		754		616		575		475		2,682		6,037
Financial guarantees		926												926

Liabilities for leased assets including related interest for €2,429 million (€2,953 million at December 31, 2019) pertained to the share of joint operators participating in unincorporated ventures 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
(€ million)	2021		2022 – 2025		2026 and thereafter		Total
December 31, 2020
Trade payables		8,679						8,679
Other payables and advances		4,257		111		94		4,462
		12,936		111		94		13,141

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	Maturity year
(€ million)	2020		2021 – 2024		2025 and thereafter		Total
December 31, 2019
Trade payables		10,480						10,480
Other payables and advances		5,065		54		100		5,219
		15,545		54		100		15,699

Expected payments under contractual obligations28

In addition to lease, financial, trade and other liabilities represented in the balance sheet, the Company is subject to non-cancellable contractual obligations or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in future reporting periods. These liabilities are valued based on the net cost for the company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligation and the contractual compensation/penalty in the event of non-performance.

The Company’s main contractual obligations at the balance sheet date comprise take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors.

The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis. Amounts expected to be paid in 2021 for decomissioning 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)	2021		2022		2023		2024		2025		2026 and thereafter		Total
Decommissioning liabilities(a)		400		237		202		425		276		10,433		11,973
Environmental liabilities		383		323		267		255		196		839		2,263
Purchase obligations(b)		8,041		7,644		7,342		8,150		8,613		63,864		103,654
- Gas
- take-or-pay contracts		6,196		6,852		6,809		7,691		8,392		63,477		99,417
- ship-or-pay contracts		893		519		480		439		212		359		2,902
- Other purchase obligations		952		273		53		20		9		28		1,335
Other obligations		2										106		108
- Memorandum of intent – Val d’Agri		2										106		108
Total		8,826		8,204		7,811		8,830		9,085		75,242		117,998

(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.

Contractual obligations related to employee benefits are indicated in note 21 — Provisions for employee benefits.

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Capital investment and capital expenditure commitments

In the next four years, Eni expects capital investments and capital expenditures of €26.9 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties.

The amounts shown in the table below include committed expenditures to execute certain environmental projects.

	Maturity year
(€ million)	2021		2022		2023		2024		2025 and thereafter		Total
Committed projects		4,264		3,983		2,890		2,204		1,334		14,675

Other information about financial instruments


	2020						2019
(€ million)	Carrying amount		Finance income (expense) recognized in				Carrying amount		Finance 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 held for trading(a)		5,502		31				6,760		127
Non-hedging and trading derivatives(b)		(19)		(415)				(125)		273
Other investments valued at fair value(c)		957		150		24		929		247		(3)
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other(d)		10,955		(213)				12,926		(409)
Financing receivables(e)		1,207		99				1,503		110
Securities(a)		55						55
Trade payables and other(a)		13,141		(31)				15,699		33
Financing payables(f)		26,686		(632)				24,518		(802)
Net assets (liabilities) for hedging derivatives(g)		(52)		(941)		661		(2)		(739)		(679)

(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 expense within “Other operating income (loss)” for €766 million (income for €287 million in 2019) and as income within “Finance income (expense)” for €351 million (loss for €14 million in 2019).

(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 impairment losses within “Net (impairment losses) reversal of trade and other receivables” for €226 million (net impairment losses for €432 million in 2019) and as income within “Finance income (expense)” for €13 million (income for €23 million in 2019), including interest income calculated on the basis of the effective interest rate of €22 million (interest income for €26 million in 2019).

(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 €92 million (income for €99 million in 2019) and net impairment losses for €1 million (net revaluations for €4 million in 2019).

(f)

In the profit and loss account, income or expense were recognized as expense within “Finance income (expense)”, including interest expense calculated on the basis of the effective interest rate of €531 million (interest expense for €647 million in 2019).

(g)

In the profit and loss account, income or expense were recognized within “Sales from operations” and “Purchase, services and other”.

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Disclosures about the offsetting of financial instruments

(€ million)	Gross amount of financial assets and liabilities		Gross amount of financial assets and liabilities subject to offsetting		Net amount of financial assets and liabilities
December 31, 2020
Financial assets
Trade and other receivables		11,681		755		10,926
Other current assets		3,719		1,033		2,686
Financial liabilities
Trade and other liabilities		13,691		755		12,936
Other current liabilities		5,905		1,033		4,872
December 31, 2019
Financial assets
Trade and other receivables		13,773		900		12,873
Other current assets		4,584		612		3,972
Financial liabilities
Trade and other liabilities		16,445		900		15,545
Other current liabilities		7,758		612		7,146

The offsetting of financial assets and liabilities related to the offsetting of: (i) receivables and payables pertaining to the Exploration & Production segment towards state entities for €753 million (€713 million at December 31, 2019) and trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €2 million (€187 million at December 31, 2019); and (ii) other assets and liabilities for current financial derivatives of €1,033 million (€612 million at December 31, 2019).

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 note 20 — 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 (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. Subsequently to Eni’s takeover, any activity for waste conferral was stopped. The defendants are certain managers of Eni Group companies, that have managed the landfill since 1991. The Municipality of Crotone is acting as plaintiff. In March 2019, the public prosecutor requested the acquittal of all defendants. The proceeding is ongoing. In April 2017, the Public Prosecutor of Crotone started another criminal proceeding concerning the clean-up

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of the area called “Farina Trappeto”. Despite the prosecuting PM asked the acquittal of all the defendants, on January 17, 2020, the GUP asked the PM to modify the charges in order to better specify modalities and timing of each disputed conduct. At the preliminary hearing on July 1, 2020, the GUP acquitted all the defendants, some for not having committed the alleged crime and others for prescription. The Company therefore decided to appeal against the sentence, in order to obtain an acquittal on the merits also in relation to the positions of the former managers of the Eni Group acquitted due to prescription.

(ii) Eni Rewind SpA — Crotone omitted clean-up. In April 2017, a further criminal case was opened by the Crotone prosecutor’s office on the reclamation activities of the Crotone site as a whole. Meanwhile, in the first half of 2018, the new clean-up project presented by the Company was deemed feasible by the Ministry of the Environment. Pending the decisions of the Public Prosecutor, a defense brief was filed to summarize the activity carried out by the subsidiary Eni Rewind (former Syndial SpA) in terms of reclamation, pointing to willingness of executing a decisive plan of action, and to obtain the dismissal of the criminal proceedings. On March 3, 2020, the Ministerial Decree approving the POB Phase 2 was issued.

(iii) Eni Rewind SpA and Versalis SpA — Porto Torres — Prosecuting body: Public Prosecutor of Sassari. In 2011, the Public Prosecutor of Sassari (Sardinia) determined that a manager responsible for plant operations at the site of Porto Torres should stand trial for alleged environmental disaster and poisoning of water and substances destined for food. The Province of Sassari, the Municipality of Porto Torres and other entities have been involved in the proceedings as civil parties seeking damages. In 2013, the Prosecutor of Sassari requested a new indictment for negligent behavior, replacing the previous allegation of willful conduct. The Third Instance Court has denied a motion to terminate the proceedings. The Public Prosecutor has re-submitted a request that the defendants would stand trial. Eni’s subsidiary Eni Rewind Spa has been summoned for third-party liability. The preliminary hearing is still ongoing.

(iv) Eni Rewind SpA and Versalis SpA — Porto Torres dock. In 2012, following a request of the Public Prosecutor of Sassari, an Italian court ordered presentation of evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by Eni Rewind SpA) and its capacity to avoid the dispersion of contamination released by the site into the nearby sea. Eni Rewind SpA and Versalis SpA 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 proceeding is ongoing.

(v) Eni Rewind SpA — The illegal landfill in Minciaredda area, Porto Torres site. The Court of Sassari, on request of the Public Prosecutor, seized the Minciaredda landfill area, near the western border of the Porto Torres site (Minciaredda area). All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure order involved also Eni Rewind pursuant to Legislative Decree No. 231/01, whereby companies are liable for the crimes committed by their employees when performing their duties. The court determined that Eni Rewind can be sued for civil liability and resolved that all defendants and the Eni subsidiary be put on trial before the Court of Sassari. The assessment for the admissibility of a civil claim is ongoing.

(vi) Eni Rewind SpA — The Phosphate deposit at Porto Torres site. In 2015, the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, seized — as a preventive measure — the area of “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster, carrying out of unauthorized disposal of hazardous wastes and other environmental crimes. Eni Rewind SpA is being investigated pursuant to Legislative Decree No. 231/01. In November 2019, a request for referral to trial was served on the Eni subsidiary. The preliminary hearing will be held on September 9, 2020. At the outcome of the preliminary hearing, the Judge pronounced against all the defendants a sentence of no place to proceed due to the statute of limitation in relation to the crimes of unauthorized management of landfills and disposal of hazardous wastes as well as against Eni Rewind SpA in relation to the liability pursuant to Legislative Decree 231/01. The Judge also ordered the indictment of the defendants before the Court of Sassari, at the hearing on May 28, 2021, limited to the alleged crime of environmental disaster.

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(vii) Eni Rewind SpA — Proceeding relating to the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna relating to the crimes of culpable manslaughter, injuries and environmental disaster, which have been allegedly committed by former Eni Rewind employees at the site of Ravenna. The site was acquired by Eni Rewind following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are 75 alleged victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. Eni Rewind asserted the statute of limitation as a defense to the instance of environmental disaster for certain instances of diseases and deaths. The court at Ravenna decided that all defendants would stand trial and held that the statute of limitation only applied with reference to certain instances of crime of culpable injury. Eni Rewind reached some settlements. In November 2016, the Judge acquitted the defendants in all the contested cases except for one, an asbestos case, for which a conviction was handed down. The defendants, the Prosecutor and the plaintiffs appealed the decision; a second instance judge ordered a complex appraisal, believing that they could not decide on the state of the proceedings, appointing three well-known experts. Eni’s defenders rejected one of them, believing that he had an interest in the matter; the Court rejected the request for recusal but the Third Instance Court, accepting the appeal of the defendants of the accused, canceled the order by postponement. On the referral, at the request of Eni’s lawyers, the Court of Appeal of Bologna, given the different composition of the judging panel, ordered the renewal of the appeal judgment and, consequently, the subsequent revocation of the order with which it had initially prepared the appraisal. On May 25, 2020, at the outcome of the discussion of the parties, the Court acquitted the defendants, and the person sued for damages in relation to 74 cases of mesothelioma, lung cancer, pleural plaques and asbestosis, took note of the res judicata of the acquittal for the disaster complaint and confirmed the conviction for a case of asbestosis. He also declared inadmissible the appeals of several claimants. The Company appealed to a Third Instance Court against the conviction for asbestosis; some claimants challenged the acquittal for other pathologies.

(viii) 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 EniMed 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 EniMed. The proceeding is ongoing.

(ix) 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. After a two-year investigation, 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 (loss of 60 KBOE/d net to Eni). 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, pursuant to Legislative Decree No. 231/01, which presumes that companies are liable for crimes committed by their employees when performing job tasks. The trial started in November 2017. At the outcome 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 request of administrative fines, the Court declared 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, while convicted six former officials of the same District with suspension of the sentence and at the same time sentenced Eni pursuant to Legislative Decree no. 231/01 to pay a fine of €

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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. The Court reserved the term of ninety days for the filing of the reasons of the sentence and an appeal will be promptly filed against all the condemnations.

(x) Eni SpA — Health investigation related to the COVA center. Beside the criminal proceeding for illegal trafficking of waste, the Public Prosecutor started another investigation in relation to alleged health violations. The Public Prosecutor requested the formal opening of an investigation with respect to nine people in relation to alleged violations of the rules providing for the preparation of a Risk Assessment Document of the working conditions at the Val d’Agri Oil Center (COVA). In March 2017, following the request of the consultant of the Prosecutor, the Labor Inspectorate of Potenza issued a fine against the employers of the COVA for omitted and incomplete assessment of the chemical risks for the COVA center. In October 2017, the Prosecutor’s Office changed the criminal allegations to disaster, murder and negligent personal injury, also alleging breaches of health and safety regulations. The proceeding is ongoing.

(xi) Proceeding Val d’Agri — Tank spill. In February 2017, the Italian police department of Potenza found a stream of water contaminated by hydrocarbon traces of unknown origin, flowing inside a small shaft located outside the COVA. Eni carried out activities at the COVA aimed at determining the origin of the contamination and identified the cause in a failure of a tank (the “D” tank) outside of the COVA, that presented a risk of extension of the contamination in the downstream area of the plant. In executing these activities, Eni performed all the communications provided for by Legislative Decree 152/06 and started certain emergency safe-keeping operations at the areas subject to potential contamination outside the COVA. Furthermore, the characterization plan of the areas inside and outside the COVA was approved by the relevant authorities, to which the Risk Analysis document was subsequently submitted. Following this event, a criminal investigation was initiated in order to ascertain whether there had been illegal environmental disaster by the former COVA officers, the Operation Managers in charge since 2011 and the HSE Manager in charge at the time of the accident, and also against Eni in relation to the same offense pursuant to Legislative Decree No. 231/01 and of some public officials belonging to local administrations for official misconduct, false and fraudulent public statements committed in 2014 and of the crime for environmental disaster and of culpable conduct committed in February 2017. The Company has paid damages of an immaterial amount almost to all the landlords of areas close to the COVA, which were affected by a spillover. Discussions are ongoing with other claimants. The likely disbursements relating to these transactions have been provisioned. In February 2018, Eni contested the reports presented in October and in December 2017 by the Italian Fire Department stating that it does not consider itself obliged to carry out the integration required, considering that the data acquired in the area affected by the event indicate, according to Eni’s assessments, that the loss was promptly and efficiently controlled and there were no situations of serious danger to human health and the environment. In April 2019, precautionary measures were ordered against three Eni employees at the COVA which, following an appeal, were canceled by the Third Instance Court. In September 2019, the Public Prosecutor requested one of those employees to be put on trial with expedited proceeding, accepted by the Judge for preliminary investigations. The judgment was suspended in order to allow the continuation of the environmental clean-up and reclamation of the site. As part of the concomitant procedure against the remaining employees and Eni as the legal entity being held liable pursuant to Legislative Decree No. 231/01, the Public Prosecutor, after issuing a notice of conclusion of the preliminary investigations, made a request for indictment. The hearings are ongoing.

(xii) 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 EniMed 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.

(xiii) Versalis SpA — Preventive seizure at the Priolo Gargallo plant. In February 2019, the Court of Syracuse at the request of the Public Prosecutor ordered the seizure of the Priolo/Gargallo plant as part of

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an ongoing investigation concerning the offenses of dangerous disposal of materials and environmental pollution, by the former plant manager of Versalis, pursuant to Legislative Decree No. 231/01. The Public Prosecutor’s thesis, according to the consultants, is that the plants covered by the provision have points of emissions that do not comply with the Best Available Techniques (BAT), therefore resulting in violation of the applicable legislation. Versalis has already implemented certain plant upgrades designed to comply with measures requested by the Public Prosecutor and his consultants. Based on this, an appeal was filed against the measure of precautionary seizure of the plant before a review court, which revoked the seizure of the plants on March 26, 2019. In March 2021, a notice of conclusion of the preliminary investigations was notified, with the formulation by the Public Prosecutor of the allegations already previously stated.

(xiv) Eni SpA — Fatal accident Ancona offshore platform. On March 5, 2019, a fatal accident occurred at the Barbara F platform in the offshore of Ancona. During the unloading phase of a tank from the platform to a supply vessel, there was a sudden failure of a part of the structure on which a crane was installed, causing the death of an Eni employee who was inside the control cabin of the crane and injuries to two other workers. The Public Prosecutor of Ancona initially opened an investigation against unknown persons and ordered further technical appraisals relating to the crane. As part of the technical assessment of the incident, the Public Prosecutor resolved to put under investigation the Eni employees who were in charge of safety standards at the involved facility. Also the Company has been put under investigation pursuant to Legislative Decree No. 231/01, which holds companies liable for the crimes committed by employees in a number of matters, including the violations of laws about safety of the workplace. The proceeding is pending in the preliminary investigation phase.

(xv) 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’s Office of Gela issued an inspection and seizure of the area called Isola 32 within the refinery of Gela, where old and new monitored landfills are located. The proceeding concerns criminal allegations of environmental pollution, omitted clean-up, negligent personal injury and illegal waste management, 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 (efficiency and efficacy of the barrier system). The Public Prosecutor acquired documents and evidence at the Syndial office in Gela and at the refinery of Gela, which, during the period January 1, 2017 – March 20, 2019, managed the facilities involved in cleaning up the groundwater area (TAF Syndial, site TAF-TAS and pumping wells and hydraulic barrier). Subsequently a decree was issued for the seizure of eleven (11) piezometers of the hydraulic barrier system with contextual guarantee notice, issued by the Public Prosecutor of Gela against nine employees of Gela Refinery and four employees of Syndial SpA. The proceedings are ongoing.

(xvi) Eni Rewind SpA and Versalis — Mantua. Environmental crime investigation. In August and September 2020, the Public Prosecutor of Mantua notified the conclusion of the preliminary investigations 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 investigations. Furthermore the above-mentioned entities were being held liable for the alleged crimes committed on their own interest by their own employees pursuant to Legislative Decree No. 231/01. The Public Prosecutor is alleging, depending on some specific areas related to the Mantua industrial hub, the crimes of unauthorized waste management, environmental damage/pollution, omitted communication of environmental contamination and omitted clean-up. Following the filing of defense briefs, the case has been dismissed against some individuals. The Public Prosecutor’s Office requested the indictment of the remaining defendants, not yet notified, confirming the allegations referred to in the closing of the investigation.

(xvii) Versalis SpA — Brindisi plant factory flares and odor emissions — Criminal procedure n. 6580/18 R.G. Mod. 44 against unknown persons. On May 18, 2018 the manager of the Versalis plant in Brindisi and two other employees were summoned in order to provide brief information regarding two episodes that occurred in April 2018 which led to the activation of the plant torches. The company collaborated with the judicial authorities to provide useful information to exclude that such events may have had a negative and significant impact on air quality. Moreover, the Company is reviewing available data as well as carrying out some important upgrading to minimize any detrimental effect, even if only visual, of the flaring phenomenon with the construction of a new ground torch facility.

At the end of May 2020, in conjunction with a scheduled shutdown of the plant, anomalous concentrations of benzene and toluene were detected; on those bases, the mayor of Brindisi ordered the

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plant shutdown. The order was issued without any technical check on the real correlation between the peaks detected in the air and the activities in progress at the plant. After a close discussion with the authorities in charge, the order was revoked. However, the Public Prosecutor acquired information and documents, also produced by the Company itself, on the aforementioned order to verify, also from a criminal point of view, any connection or responsibilities.

The proceeding has been filed for the time being against unknown persons and it is not possible to exclude that this event may be the subject of a proceeding from the Public Prosecutor’s Office. The company is providing all the involved local authorities with all the useful information for the correct reconstruction of the facts.

(xviii) 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 issued a notice of conclusion of the preliminary investigations, contesting, among others, the former manager of the Eni fuel storage hub of Civitavecchia, the alleged crime of environmental pollution in relation to the mismanagement of the hydraulic barrier placed over the site aimed at putting under emergency safety the contaminated groundwater, as part of the clean-up process in progress. This circumstance would have been reported by officials of a local authority (ARPA), to whom technical feedback has been provided several times over the years. Eni is under investigation pursuant to Legislative Decree 231/2001. The prosecutor made a request for indictment.

1.2 Civil and administrative proceedings in the matters of environment, health and safety

(i) Eni Rewind SpA — Summon for alleged environmental damage caused by DDT pollution in Lake Maggiore. In May 2003, the Ministry for the Environment claimed compensation from Eni Rewind for alleged environmental damage caused by the activity at the Pieve Vergonte plant in the years 1990 through 1996. In July 2008, the District Court of Turin ordered Eni Rewind to pay environmental damages amounting to €1,833.5 million, plus interests accrued from the filing of the decision. Eni and its subsidiary deemed the amount of the environmental damage to be absolutely groundless as the sentence lacked sufficient elements to support such a material amount of the liability from the volume of pollutants ascertained by the Italian Environmental Minister. In July 2009, Eni Rewind filed an appeal and consequently the proceeding continued before a second Instance Court of Turin that requested a technical appraisal on the matter. The consultants that undertook this appraisal concluded that: (i) no further measure for environmental restoration is required; (ii) there was no significant and measurable impact on the environment of the ecosystem, therefore no restoration or damage compensation should be claimed; the only impact seen concerned fishing activity, with an estimated damage of €7 million which could be already restored through the measures proposed by Eni Rewind, and; (iii) the necessity and convenience of dredging should be excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the Eni Rewind’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. In March 2017, the second Instance Court: (i) excluded the application of compensation for monetary equivalent; (ii) annulled the monetary compensation of €1.8 billion requesting Eni Rewind to perform the already approved clean-up project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The value of these compensatory works required by the Court, in case of Eni Rewind failure or misperformance, is estimated at €9.5 million. The clean-up project filed by Eni Rewind was ratified by the authorities and is currently being executed. Expenditures expected to be incurred have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were rejected by the court (including compensation for non-material damage). In April 2018, the Ministry for the Environment filed an appeal to the Third Instance Court. Following this appeal, the Company appeared in Court. After the hearings in July 2020 and in January 2021, the sentence is still ongoing.

(ii) Eni Rewind SpA — Versalis SpA — Eni SpA (R&M) — Augusta harbor. The Italian Ministry for the Environment with various administrative acts required companies that were operating plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor.

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Companies involved include Eni subsidiaries Versalis, Eni Rewind and Eni Refining & Marketing Division. Pollution has been detected in this area primarily due to a high mercury concentration that is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above-mentioned companies contested these administrative actions, objecting in particular to the nature of the remediation works decided and the methods whereby information on the pollutants concentration has been gathered. A number of administrative proceedings started on this matter were subsequently merged before the Regional Administrative Court. In October 2012, the Court ruled in favor of Eni’s subsidiaries against the Ministry’s requirements for the removal of the pollutants and the construction of a physical barrier. In September 2017, the Ministry notified all the companies involved of a formal notice for the start of remediation and environmental restoration of the Augusta harbor within 90 days, basing its request on an alleged ascertainment of liability on the basis of the 2012 provision of Regional Administrative Court. The act, contested by the co-owner companies in December 2017, constitutes a formal notice for environmental damage. In June 2019, the Italian Ministry for the Environment set up a permanent technical committee to review the matter of the clean-up and reclamation of the Augusta harbor. The report, recalling the warning of 2017, confirmed the thesis of the parties on the responsibility of the companies co-located for the contamination of the Rada and affirmed a breach of the aforementioned warning by the companies, also communicated to the Public Prosecutor's Office. In agreement with all the other companies involved, this report and other parallel internal technical investigations were challenged for defensive purposes. Eni’s subsidiary proposed to the Italian Environmental Ministry to start a collaboration with other interested parties to find remediation measures based on new available environmental data collected by independent agencies, without prejudice to the need for the parties to correctly identify the legal entity responsible for the contamination detected. In the meantime, the company requested, in full compliance with applicable environmental laws, to establish a roadmap for identifying the companies accountable for the environmental pollution and their respective shares of responsibility in order to implement a clean-up and remediation project.

In September 2020, the Company took part in the Investigation Services Conference convened by the Ministry of the Environment on the results of the technical investigations and exhibited, together with its consultants, the in-depth analyzes on the environmental state of the Rada and its observations to the report which would lead to the exclusion of any involvement of the Group companies in the contamination detected.

(iii) Eni SpA — Eni Rewind SpA (former Syndial SpA) — Raffineria di Gela SpA — Claim for preventive technical inquiry. 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 judgement has been appealed.

(iv) Environmental claim relating to the Municipality of Cengio. Since 2008 a proceeding is pending by the Court of Genoa, brought by The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio. Those parties summoned Eni Rewind before a Civil Court and demanded Eni’s subsidiary compensate for the environmental damage relating to the site of Cengio. The request for environmental damage amounted to €250 million to which was to be added health damage to be quantified during the proceeding. The plaintiffs accused Eni Rewind of negligence in performing the clean-up and remediation of the site. In March 2019, the Ministry for the Environment presented a proposal to Eni Rewind to settle the case. The Company responded with a counterproposal in July 2019. In September 2020, the debate reopened and the drafting of an agreement shared between the parties and considered to be final also by the representatives of the Ministry was reached. The Ministry, through the Attorney's Office, at the hearing in February 2021, declared the “advanced state” of the negotiations, thus allowing the hearing to be postponed to June 2021.

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In March 2021, the Inspection Commission also issued a test certificate for the works carried out on the soils, thereby further strengthening the restorative suitability of the measures carried out by the Company.

(v) Val D’Agri — Eni / Vibac. In September 2019 a claim was brought in the Court of Potenza against Eni. The plaintiffs are eighty 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. In particular, the claim refers to certain events which allegedly caused damage to the local community and the territory (such as a 2017 spill, flaring events since 2014, smelly and noisy emissions). The Judge has been asked to ascertain Eni’s responsibility for causing emissions of polluting substances into the atmosphere. The plaintiffs have also requested Eni be ordered to interrupt any polluting activity and to 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 that Eni compensate all direct and indirect property damages, current and future, to an extent that will be quantified in the course of the case. At the end of the trial phase, the Judge sent the parties the proposal for an extra-judicial settlement, putting a deadline to present further proposals on the matter.

(vi) Eni SpA — Climate change. In 2017 and 2018, local government authorities and a fishing association brought in the courts of the State of California seven proceedings against a controlled entity (Eni Oil & Gas Inc.) and other oil companies. These proceedings claim compensation for the damages attributable to the increase in sea level and temperature, as well as to the hydrogeological instability. The cases have been transferred, by request of the defendants, from the State Courts to the Federal Courts. A specific request has been filed, highlighting the lack of jurisdiction of the State Courts. Following a suspension period waiting for the decision on jurisdiction, on May 26, 2020 the proceedings returned to the State Courts. On July 9,2020, Eni Oil & Gas Inc, together with other defendants, signed a petition for rehearing “en blanc” to request a review of the postponement decision to the competent “9th Circuit Court”. The disputes will remain suspended until a decision made on the petition for rehearing. The Court rejected the petition for rehearing en banc but, at the request of the defendants, granted a suspension of the proceedings of 120 days (until January 2021) to allow the defendants themselves to present a so-called petition for certiorari to the Supreme Court of the United States in order to obtain the revision of rejection. The petition was presented in January 2021 by the defendant; the Supreme Court of the United States will rule on the matter by June 2021.

(vii) Eni Rewind / Province of Vicenza — Clean-up process for Trissino site. On May 7, 2019 the Province of Vicenza imposed (with a warning) on some persons and companies as MITENI SpA in bankruptcy, Mitsubishi and ICI, to clean-up the Trissino site where MITENI carried out its industrial activity. In this site, in 2018, based on the analysis carried out by administrative parties, significant concentrations of substances considered highly toxic-harmful and carcinogenic were allegedly discovered in groundwater and in surface water. 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 action of health analysis and monitoring by the institutions is destined to increase. The Province warned some individuals, including a former employee who served between 1988 and 1996 as CEO of a company that was taken over by Eni Rewind.

In an initial phase of the administrative procedure, there were no references to the former company Enichem Synthesis, which Eni Rewind took over, therefore the legal assistance and the defense strategy were concentrated supporting only the persons involved. Instead, several appeals to the Regional Administrative Court have arisen in which Eni Rewind was called into question as the “successor” of Enichem for the period of management of the site as the majority shareholder of MITENI. On the basis of this, in February 2020, the Province extended the proceeding also to Eni Rewind which set a procedural brief for the prompt filing of the proceeding against it.

However, on October 5, 2020 the Province notified a warning with which it would have identified Eni Rewind as further responsible for the potential contamination of the Trissino site. On December 4, 2020 Eni Rewind appealed to the Administrative Court, pending the setting of the hearing.

Eni Rewind was also invited to take part in several meetings that will be held by the Public Entities in relation to the site remediation interventions, and has already participated in the first one held on December 23, 2020, without thereby granting any acquiescence to the provisions issued by the Province.

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Access to the documents is ongoing with the Public Authorities aimed at acquiring a complete knowledge of the facts and being able to integrate the defenses in these proceedings. In order to carry out a transversal study on the issue of PFAS, the company has established a Working Group (WG) that will analyze the technical-environmental, toxicological and regulatory aspects also addressing the issue with an international approach. In addition to Eni Group personnel, three external competent consultants for the respective subjects are part of the WG.

2. Proceedings concerning criminal/administrative corporate responsibility

(i) Block OPL 245 — Nigeria. A criminal case is ongoing before the Court of Milan alleging international corruption in connection with the acquisition in 2011 of the OPL 245 exploration block in Nigeria. In July 2014, the Public Prosecutor of Milan served Eni with a notice of investigation pursuant to Italian Legislative Decree No. 231/01. The proceeding was commenced following a claim filed by NGO ReCommon relating to alleged corruptive practices which, according to the Public Prosecutor, allegedly involved the Resolution Agreement made on April 29, 2011 relating to the so-called Oil Prospecting License of the offshore oilfield that was discovered in OPL 245. Eni fully cooperated with the Public Prosecutor and promptly filed the requested documentation. Furthermore, Eni voluntarily reported the matter to the US Department of Justice and the US SEC. In July 2014, Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage an independent, US-based law firm, expert in anticorruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. After reviewing the matter, the US lawyers concluded that they detected no evidence of wrongdoing by Eni in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. In September 2014, the Public Prosecutor notified Eni of a restraining order issued by a British judge who ordered the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the Public Prosecutor. Since the act had also been notified to some persons, including the CEO of Eni and the former Chief Development, Operation & Technology Officer of Eni and the former CEO of Eni, it was assumed that the same had been registered in the register of suspects at the Milan Prosecutor’s office. During a hearing before a court in London in September 2014, Eni and its current executive officers stated their non- involvement in the matter regarding the seized bank account. Following the hearing, the Court reaffirmed the seizure. In December 2016, the Public Prosecutor of Milan notified Eni of the conclusion of the preliminary investigation and requested Eni’s CEO, the Chief Development, Operations and Technological Officer and the Executive Vice President for international negotiations to stand trial, as well as Eni’s former CEO and Eni SpA, pursuant to Italian Legislative Decree No. 231/01. Upon the notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor, the independent US-based law firm was requested to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the prior review. The US law firm was also provided with the documentation filed in the Nigerian proceeding mentioned below. The independent US law firm concluded that the reappraisal of the matter in light of the new documentation available did not alter the outcome of the prior review. In September 2019, the DoJ notified Eni that based on the information it currently possessed, the DoJ was closing its investigation of Eni in connection with OPL 245 without the filing of any charges. In December 2017, the Judge for preliminary investigation ordered the indictment of all the parties mentioned above, and other parties under investigation by the Public Prosecutor, before the Court of Milan. The request of the Federal Government of Nigeria (FGN) for admission as a civil claimant in the proceedings was granted in July 2018. The first instance trial of the Milan Prosecutor’s OPL 245 charges began before the Court of Milan on June 20, 2018. Following the discussion of the parties, in response to the request for conviction for all the individuals and companies involved, at the hearing of March 17, 2021 the judge fully acquitted all the defendants, since there was no case.

In January 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd (“NAE”) became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court upon request from the Nigerian Economic and Financial Crimes Commission (EFCC), attaching OPL 245 temporarily pending a proceeding in Nigeria relating to alleged corruption and money laundering. After making this application, Eni became aware of a formal filing of charges by the EFCC against NAE and other parties. In March 2017, the Nigerian Court revoked the Order. To NAE’s knowledge EFCC charges have not been dropped but none of the defendants were served nor arraigned. In November 2018, Eni SpA and its subsidiaries NAE, NAOC and AENR (as well as some companies of the Shell Group) were notified of the intention of the FGN to bring a civil claim before an English court to obtain compensation for damages

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allegedly deriving from the transaction that resulted in assignment of the OPL 245 to NAE and Shell subsidiary SNEPCO (Shell subsidiary). On April 15, 2019 the Nigerian subsidiaries NAE, NAOC and AENR received formal notification of the commencement of the proceeding, while similar notification was received by Eni SpA on May 16, 2019. In the introductory deeds of the proceeding, the claim is set at $1,092 million or at any other amount that will be established during the proceedings. The FGN has based its assessment on an estimated fair value of the asset of $3.5 billion. Eni’s interest in the asset is 50%. As the FGN is also acting as claimant in the Italian proceeding before the Court of Milan, this claim appears to duplicate the claims made before the Milan’s Court against Eni employees. On May 22, 2020, the Judge accepted the exception presented by Eni and declined its jurisdiction over the case, having found the judicial pending with the Milan procedure according to the criteria set out in Regulation (EU) No 1215/2012. The Appeal Court obtained permission to appeal against the decision. Similarly, the Appeal Court rejected the Nigerian Government’s request to appeal the decision, thus making it definitive.

On January 20, 2020, NAE subsidiary was notified of the beginning of a new criminal case before the Federal High Court in Abuja. The proceeding, mainly focused on the accusations against Nigerian persons (including the Minister of Justice in office in 2011, at the time of the disputed facts), involves NAE and SNEPCO as co-holders of the OPL 245 license. These persons were attributed in 2011 illicit acts of corruptive nature, which NAE and SNEPCO would have unlawfully facilitated. The beginning of the trial, scheduled for the end of March 2020, has been postponed for the closure of the judicial offices in Nigeria due to COVID-19 emergency. A new hearing has not been scheduled to date.

(ii) Congo. In March 2017, the Italian Finance Police served Eni with an information request in accordance with the Italian Code of Criminal Procedure in connection with an investigative file opened by the Public Prosecutor of Milan against unknown persons. The request related in particular to the agreements signed by Eni Congo SA with the Ministry of Hydrocarbons of the Republic of Congo in 2013, 2014 and 2015 in relation to exploration, development and production activities concerning certain permits held by Eni Congo SA for Congolese projects and Eni’s relationships with Congolese companies that hold stakes in those projects. In July 2017, the Italian Financial Police, on behalf of the Public Prosecutor of Milan, served Eni with another information request and a notice of investigation pursuant to Legislative Decree No. 231/01 for alleged international corruption. The request expressly stated that it was based in part on the March 2017 information request and concerned the relationship of Eni and its subsidiaries with certain third-party companies from 2012 to the present. Eni produced all of the documentation requested in March and July 2017 and voluntarily disclosed this matter to the relevant US authorities (SEC and DoJ). In January 2018, the Public Prosecutor’s Office requested a six-months extension of the deadline for conducting its preliminary investigation into this matter, from January 31, 2018 until July 30, 2018. Subsequently in July 2018, the Public Prosecutor requested a second extension until February 28, 2019. In April 2018, the Public Prosecutor of Milan served Eni SpA with a further request for documentation and notified a former Eni employee, who was the then Chief Development, Operation & Technology Officer, of a search order stating that he and another Eni employee had been placed under investigation.

In October 2018, the Public Prosecutor ordered the seizure of an e-mail account of another Eni manager, who was formerly the general director of Eni in Congo during the period 2010 – 2013. In December 2018 and subsequently in May, September and December 2019, Eni was notified by the Public Prosecutor of Milan of a request for documents in accordance with the Italian Code of Criminal Procedure, concerning some economic transactions between Eni Group companies and certain third-party companies. All the required documentation has been produced to the Judge.

In September 2019, the Company was informed that the Company’s CEO was served with a search decree and an investigation decree in connection with an alleged violation of article 2629 bis of the Italian Civil Code which penalizes directors of listed companies, who fail to communicate conflicts of interest. The alleged omission relates to the supply of logistics and transportation services to certain Eni’s subsidiaries operating in Africa, among which Eni Congo SA, by third-party companies owned by Petroserve Holding BV, in the period 2007-2018. The claims are based on the allegations that the wife of the Company’s CEO retained a shareholding of the above-mentioned holding company during part of the period of time under investigation. The Board of Directors of Eni SpA has never been involved in any resolution concerning the suppliers under investigation. Subsequently, on June 15, 2020, the company was informed that an extension of the investigations relating to these allegations was requested until December 21, 2020.

In April 2018, the Board of Statutory Auditors, the Watch Structure and the Control and Risk Committee of Eni jointly appointed an independent law firm and a professional consulting company,

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knowledgeable in the matter of anti-corruption, to carry out a forensic review of facts relating to Eni’s work in Congo. Such review did not find any factual evidence as to the involvement of Eni, nor of any Eni employees and key managers, in the alleged crimes.

In November 2019, following the notification of further investigative documents, the Board of Statutory Auditors, the Watch Structure of Eni and the Control and Risk Committee asked the professional consultants, which had been engaged in 2018, also to review the conclusions reached, in the light of the documentation made available following the decree notified to the CEO in September 2019. The second report of the consultants, which was delivered in July 2020, integrates the findings achieved in the first report, particularly indicating that: (i) it is probable that the CEO’s wife retained a shareholding in the Petroserve Group for a few years, at least, starting from 2009 until 2012; (ii) there is an absence of evidence to contradict the statements made by the CEO as to his lack of knowledge of his wife’s interests in the ownership of Petroserve Group; (iii) absence of evidence that the activity of the abovementioned involved employees was carried out in the interest of Eni.

On September 9, 2020, Eni was notified of a decree, setting a hearing due to the filing by the Public Prosecutor of Milan requesting a restrictive measure pursuant to Legislative Decree No. 231/01, relating to some oilfields in Congo. In particular, the Judge requested Eni to be banned from exploiting Djambala II, Foukanda II, Mwafi II, Kitina II, Marine VI Bis, Loango, Zatchi oilfields for 2 years and subordinately the appointment of a judicial commissioner to manage those oilfields.

The Judge for Preliminary Investigations in the decree setting the hearing for September 21, 2020, recognized the above-mentioned restrictive measure would have been statute barred on July 14, 2020, since the date of commission of the alleged crimes was mentioned by the public prosecutors till July 14, 2015. However, this five-year limitation term would have been suspended due to the recent anti-covid legislation until September 16, 2020. The Judge also stated that a claim was pending before the Constitutional Court about the constitutional legitimacy of the aforementioned anti-covid legislation, with particular reference to the principle of non-retroactivity of an unfavorable rule. Therefore, the hearing initially set for September 21, 2020, was postponed initially to December 10, 2020 pending the resolution of the Constitutional Court and then, once the Court resolved to declare the legitimacy of the anti-covid rule to February 17, 2021 also to await the filing of the reasons for the sentence.

The hearing of February 17, 2021 was postponed to March 25, 2021, due to the fact that the Public Prosecutor changed the charge from international corruption to undue inducement to give or promise benefits, a possible course of action was explored whereby the public prosecutor and the defendant may request the judge to apply a penalty. On March 15, 2021, the Board of Directors of Eni SpA approved the granting of a special power of attorney in favor of the defense lawyer of Eni SpA, the entity legally liable, to propose a motion to apply a penalty on request of the parties. The sanction agreed with the Public Prosecutor amounts to €11.8 million.

At the hearing on March 25, 2021 the Judge for Preliminary Investigations accepted the agreed sanction and the Prosecutor also revoked the request for restrictive measure for Eni SpA.

3. Other proceedings concerning criminal matters

(i) Eni SpA (R&M) — Criminal proceedings on fuel excise tax. A criminal proceeding is currently pending, relating to alleged evasion of excise taxes in the context of retail sales in the fuel market. In particular, the claim states that the quantity of oil products marketed by Eni was larger than the quantity subjected to the excise tax. This proceeding (No. 7320/2014 RGNR) concerns the combination of distinct investigations: (i) A first proceeding, opened by the Public Prosecutor’s Office of Frosinone involved a company (Turrizziani Petroli) purchaser of Eni’s fuel. This investigation was subsequently extended to Eni. The Company fully cooperated and provided all data and information concerning the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. (ii) A second proceeding concerning an investigation by the Public Prosecutor’s Office of Prato, commenced in regard to the deposit of Calenzano and relates to abduction 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, concerns alleged missing payment of excise tax on the surplus of the unloading products, as the quantity of such products was larger than the quantity

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reported in the supporting fiscal documents. This proceeding represents a development of the first proceeding mentioned above and substantially concerns similar facts presenting, however, some differences with regard to the nature of the alleged crimes and the responsibility.

The Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at habitual abduction of oil products at all of the 22 storage sites which are operated by Eni in Italy. Eni is cooperating with the Prosecutor in order to defend the correctness of its operation. In September 2014, a search was conducted at the office of the former chief of the R&M Division in Rome. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also relate to a period of time when the officer was in charge at Eni’s R&M Division. In March 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer at the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. The proceeding was then extended to a large number of employees and former employees of the Company. Eni has continued to provide full cooperation to the authorities.

During 2018, as part of the general proceeding no. 7320/2014, the Public Prosecutor of Rome notified the conclusion of the preliminary investigations in relation to the criminal proceeding concerning the Calenzano, Pomezia, Naples, Gaeta and Ortona storage sites and the Livorno and Sannazzaro refineries. Based on the outcome of the investigations, as far as Eni is concerned, the proceeding involves former managers and directors of the logistic sites and refineries indicated above concerning alleged aggravated and continuous non-payment of excise duties, alteration and removal of seals, use and possession of false measures and weights instruments. In addition, for the Calenzano site, three employees and their manager of the storage site were accused of alleged procedural fraud.

In September 2018, Eni received, as 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 numerous persons under investigation — including over forty Eni employees — subject of a separated proceeding (No. 22066/17 RGNR), for which, in May 2017, the Public Prosecutor’s Office had requested the dismissal. At the end of the hearing in December 2018, the Judge accepted the request for dismissal for several persons under investigation, including thirteen Eni employees. The Judge also initially rejected the request of indictment for criminal association relating to twenty-eight Eni employees (including the former managers of the R&M Division).

As part of the separate proceeding no. 22066/2017 RGNR, following the re-filing by the Public Prosecutor of the indictment for criminal association, following a preliminary hearing, the judge resolved to dismiss the case against all of the defendants because allegations were found to be groundless.

(ii) Eni SpA — Public Prosecutor of Milan — Criminal proceeding no. 12333/2017. In February 2018, Eni was notified of a search and seizure decree in relation to allegations of associative crime aimed at slander and at reporting false information to a Public Prosecutor. In the decree, the Prosecutor of Milan included, among the other persons under investigation, a former external lawyer and a former Eni manager, at the time of the facts holding strategic positions in the Company. According to the decree, the association is allegedly aimed at interfering with the judicial activity in certain criminal proceedings that are involving, among others, Eni and some of its directors and managers. Afterwards, the Control and Risks Committee, having consulted the Board of Statutory Auditors, and together with the Watch Structure, agreed to engage an auditing firm to perform an internal audit of all relevant facts and circumstances and all records and documentation relating to the matter with respect to the events of the aforementioned proceeding, including a forensic review. The final report, submitted to the Control and Risk Committee, the Watch Structure and the Board of Statutory Auditors on September 12, 2018, concluded that following the review carried out with respect to the allegations made by the Public Prosecutor of Milan, there was not sufficient factual evidence to prove the involvement of the aforementioned former manager of Eni in the alleged crimes. On April 19, 2018, the Board of Directors appointed two external consultants, a criminal lawyer and a civil lawyer to provide independent legal advice in relation to the facts under investigation. Their report, dated November 22, 2018, did not find facts which could suggest any involvement of any Eni employees in the crimes alleged by the Public Prosecutor. On June 4, 2018, Consob, the Italian market regulator, requested to be informed about the above-mentioned proceeding. The request was addressed to the Company and to its Board of Statutory Auditors.

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Specifically, Consob asked for the outcome of the forensic review and to be updated about any other audit action taken in relation to the matter by the Company and by its Board of Statutory Auditors. The Board of Statutory Auditors was also requested to report about the findings of the additional audit program agreed with an external auditor regarding the matter and to keep Consob updated about any further initiatives adopted. The Company answered the request on June 11, 2018. Subsequently, the Company finalized its response by sending further documentation including the final report of the independent third party and the reports of the consultants of the Board of Directors. The Board of Statutory Auditors has periodically updated Consob of the initiatives taken as part of the Board’s monitoring responsibilities with several communications, the last of which on July 25, 2020. On June 13, 2018, Eni was notified of a request from the Prosecutor Office to transmit certain documentation in accordance with the Italian Code of Criminal Procedure. The request targeted evidence and documents relating to the internal audit performed by the Company and any possible external review concerning certain tasks that had been assigned to the former external lawyer with respect to Eni. This lawyer appears to be investigated as part of this proceeding. The reports of the independent third party and of the consultant of the Board of directors were also sent to the Public Prosecutor.

In May and June 2019, in the context of the same proceeding, the Court of Milan notified Eni and three of its subsidiaries (ETS SpA, Versalis SpA, Ecofuel SpA) of various requests for documentation in accordance with the Italian Code of Criminal Procedure. At the same time, on May 23, 2019, Eni was served a notice that the Company is being investigated pursuant to Legislative Decree No. 231/01, with reference to the crime sanctioned by the Italian Penal Code concerning “inducement not to make statements or to make false statements to the judicial authority”.

The object of the aforementioned requests particularly concerned the relations with two business partners, access to Eni offices of certain third parties, also on behalf of one of the above-mentioned business partners, the mailbox of some employees and former employees, the documentation concerning the relations (and the interruption of those relations) with the former external lawyer investigated in the proceeding, the internal audit reports and the reports of the Company’s bodies that dealt with assessing these relationships. Following internal audits, on June 21, 2019, the Company sued for fraud a former employee at its subsidiary ETS, who was fired on May 28, 2019, and also filed a complaint before the Judicial Authority to ascertain possible complicity in fraud of other third parties.

On August 14, 2019, the Italian tax police sent a new request for information to Eni, concerning the economic relations between Eni Group companies and an external professional.

In November 2019, Eni received a notice to extend the preliminary investigations. The notice also covered the investigations of the alleged breach of certain provisions of Italian Law Decree 231/01 until May 2020 on part of Eni. Furthermore, it was ascertained that certain former Eni employees have been charged with various criminal allegations. Those employees were a former manager of Eni’s legal department, the former Chief Upstream Officer of Eni and an employee that was fired in 2013. A number of third parties have also been indicted, among them, two former legal consultants of Eni. On January 23, 2020, a search decree and an indictment were notified to the Company’s Chief Services & Stakeholder Relations Officer, the Senior Vice President for Security and to a manager of the legal department. Following the requests for review of the aforementioned decree, the material deposited by the Public Prosecutor’s Office was made available to the Company, which requested its examination by the same consultants appointed in 2018 to examine the documentation. Subsequently, in June, July and September 2020, Eni was notified by the Public Prosecutor of Milan of several requests for documentation concerning, in particular: the results of the inquiries carried out by the internal audit following an anonymous report relating to a hospitality event in 2017; some clarifications regarding an invoice issued by an external law firm; the internal audit report on relations with a commercial third part; work commitments of the Chief Services & Stakeholder Relations Officer relating to certain dates of 2014 and 2016; the documentation concerning the dismissal of a former Eni employee. All the required documentation has been produced over time to the Judicial Authority.

On November 9, 2020, the Company was informed of the notification to Eni’s CEO of a technical assessments notice, with contextual guarantee information aimed at allowing participation, through its consultant, in the scheduled review of the content of a telephone device seized from a former Eni employee.

(iii) Eni SpA — Public Prosecutor of Milan — Insider trading. In March 2019, a request for extending certain investigations was notified to Eni’s former Chief Upstream Officer by the public prosecutor office

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of Milan. The commencement of the investigations was otherwise not notified. The investigations related to an alleged breach of Italian provisions that regulate insider trading and access to market-sensitive information. The breach was allegedly made from November 1 to December 1, 2016. There were no more informative details about the alleged breach in the notified document. This investigation has been combined into the abovementioned one.

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&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 124/2019 (enacted with Law 157/2019) 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) EniPower SpA. In 2004, the Public Prosecutor of Milan commenced inquiries into contracts awarded by Eni’s subsidiary EniPower SpA and as to supplies provided by other companies to EniPower SpA. It emerged that illicit payments were made by EniPower SpA suppliers to a manager of EniPower SpA who was immediately fired. The Court served EniPower SpA (the commissioning entity) and Snamprogetti SpA, now Saipem SpA (contractor of engineering and procurement services), with notices of investigation pursuant to Legislative Decree No. 231/01. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers pursuant to Legislative Decree No. 231/01. Eni SpA, EniPower SpA and Snamprogetti SpA presented themselves as plaintiffs. In September 2011, the Court of Milan found that nine persons were guilty for the above-mentioned crimes. In addition, they were sentenced jointly and severally to the payment of all damages to be assessed through a specific proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations, while the trial ended with an acquittal of 15 defendants. In reference to the parts involved in the proceeding pursuant to Legislative Decree No. 231/01, the Court found that 7 companies are responsible for the administrative offenses ascribed to them, imposing a fine and the disgorgement of profit. The Court rejected the position as plaintiffs of the Eni Group companies, reversing the prior decision made by the Court. This decision may have been made based on a pronouncement made by a Third Instance Court that stated the illegitimacy of the constitution as plaintiffs against any legal entity, as indicted pursuant to Legislative Decree No. 231/01. The sentenced parties filed appeal against the above-mentioned decision. The Appeal Court issued a ruling that substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. The Third Instance Court successively annulled the judgment of the Second Instance Court ascribing the judgment to another section that, once more, confirmed the sentence of first instance, excepting the rulings of the previous appeal sentence not subject to annulment, including the statute of limitation. The grounds of the sentence have been filed confirming the motivations provided by the previous instance Courts. An appeal was filed at the Third Instance Court solely for the purposes of the civil proceeding. Following this ruling by the Court, the criminal proceedings can be considered concluded.

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(ii) Eni Rewind SpA — Environmental disaster at Ferrandina. In January 2018, the Public Prosecutor of Matera commenced a criminal proceeding against a manager of the Eni subsidiary Eni Rewind based on allegations of unlawful handling of waste and environmental disaster as part of the reclaiming activities performed at an industrial site (Ferrandina/Pisticci in the south of Italy). The charge related to an alleged spillover of effluent in the subsoil and then in a nearby river due to a damaged pipe dedicated to the transportation of effluent to a disposal plant owned by a third party. At the preliminary hearing in October 2019, the Judge dismissed the case on the basis that the defendant did not commit any crime. The sentence has become final.

(iii) Algeria. On January 15, 2020, the second penal section of the Court of Appeal of Milan confirmed the first-degree acquittal sentence against the former Eni managers in relation to the disputes for the acquisition of the FCP by Eni, declaring the appeal proposed by the Public prosecutor inadmissible against the Company. On June 12, 2020, the General Prosecutor filed an appeal in Third Instance Court for the part of the proceeding relating to Saipem, not expressly challenging the heads and points of the judgment relating to the so-called “Eni affair — FCP”. The Third Instance Court rejected the appeal pronounced against Saipem, its former managers and third party accused. In 2012, Eni contacted the US Department of Justice (DoJ) and the US SEC in order to voluntarily inform them about this matter and has kept them informed about the developments in the Italian Prosecutors’ investigations and proceedings. Following Eni’s notification, both the US SEC and the DoJ started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests. The DoJ notified Eni that based on the information it currently possessed, closing its investigation of Eni in connection with Eni’s and Saipem’s businesses in Algeria without the filing of any charges, ordering the closure of the proceeding as communicated to the market on October 1, 2019. In April 2020 Eni, having informed SEC of the acquittal pronounced on appeal on January 15, 2020, however concluded the investigation by the US SEC on Algerian activities of Saipem SpA, with a transaction that does not involve the admission of responsibility. The agreement provided for the payment of USD 19,750,000, which represents Eni’s part of the tax benefits obtained by Saipem in relation to the costs incurred by Saipem, which are non-deductible, in addition to a sum of compensation for interest equal to USD 4,750,000.

(iv) Eni Rewind SpA and Versalis SpA — Summon for alleged environmental damage caused by illegal waste disposal in the municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Eni Rewind and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff alleged Eni Rewind and Versalis were responsible because they produced the waste and commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001-2003 which would have allegedly traced the hazardous waste materials back to the Priolo and Gela industrial sites that are managed by the above-mentioned Eni’s subsidiaries (in particular, the waste with high mercury concentration and railway sleepers no longer in use). Such waste was allegedly handled and disposed illegally at an unauthorized landfill owned by a third party. Two subsidiaries of Eni and a third-party waste company were claimed to be jointly and severally liable for damage amounting to €500 million. The third-party company executed waste disposal at the site. In June 2017, the Judge accepted all the defensive instances of Eni Rewind and Versalis, judging the requests of the Municipality to be inadmissible for lacking right to sue, also considering the requests to be unfounded or unproved, and ordered the Municipality to refund the expenses of the proceeding. In April 2018, the First Instance Judge rejected the counterclaim filed by the Municipality. In July 2020, the appeal to the Third Instance Court was held. The Judge confirmed the outcome of the previous degrees of judgment, only ordering the Company to pay the expenses of the proceeding that the Company promptly provided.

Assets under concession arrangements

Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing 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

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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 Refining & Marketing 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 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The new phase marked a significant change in the method of awarding emission allowance from a no-consideration scheme based on historical emissions to allocation through auctioning. For the period 2013 – 2020, the award of free emission allowances is performed based on European benchmarks specific to each industrial segment, except for the thermoelectric 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 2020, 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 17.32 million tonnes, Eni was awarded free emission allowances of 6.84 million tonnes, determining a deficit of 10.48 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market.

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28 Revenues and other income

Sales from operations


(€ million)	Exploration & Production		Global Gas & LNG Portfolio		Refining & Marketing and Chemical		Eni gas e luce, Power & Renewables		Corporate and Other activities		Total
2020
Sales from operations		6,359		5,362		24,937		7,135		194		43,987
Products sales and service revenues
Sales of crude oil		1,969				9,024						10,993
Sales of oil products		517				11,852						12,369
Sales of natural gas and LNG		3,505		5,000		20		2,741				11,266
Sales of petrochemical products						3,277				19		3,296
Sales of other products		113		(2)		36		2,366		2		2,515
Services		255		364		728		2,028		173		3,548
Total		6,359		5,362		24,937		7,135		194		43,987
Transfer of goods/services
Goods/Services transferred in a specific moment		5,896		5,239		24,639		7,135		78		42,987
Goods/Services transferred over a period of time		463		123		298				116		1,000
2019
Sales from operations		10,499		9,230		41,976		7,972		204		69,881
Products sales and service revenues
Sales of crude oil		3,505				17,361						20,866
Sales of oil products		1,189				19,615						20,804
Sales of natural gas and LNG		5,454		8,881		214		3,373				17,922
Sales of petrochemical products						4,088				22		4,110
Sales of other products		68				16		2,503		6		2,593
Services		283		349		682		2,096		176		3,586
Total		10,499		9,230		41,976		7,972		204		69,881
Transfer of goods/services
Goods/Services transferred in a specific moment		9,946		9,117		41,727		7,972		86		68,848
Goods/Services transferred over a period of time		553		113		249				118		1,033

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(€ million)	Exploration & Production		Global Gas & LNG Portfolio		Refining & Marketing and Chemical		Eni gas e luce, Power & Renewables		Corporate and Other activities		Total
2018
Sales from operations		9,943		11,931		46,088		7,684		176		75,822
Products sales and service revenues
Sales of crude oil		3,982				18,471						22,453
Sales of oil products		1,133				21,266						22,399
Sales of natural gas and LNG		4,554		11,575		166		3,347				19,642
Sales of petrochemical products						5,539				35		5,574
Sales of other products		27		1		20		2,362		11		2,421
Services		247		355		626		1,975		130		3,333
Total		9,943		11,931		46,088		7,684		176		75,822
Transfer of goods/services
Goods/Services transferred in a specific moment		9,676		11,801		46,029		7,684		106		75,296
Goods/Services transferred over a period of time		267		130		59				70		526

(€ million)	2020		2019		2018
Revenues associated with contract liabilities at the beginning of the period		818		747		342
Revenues associated with performance obligations totally or partially satisfied in previous years				10		11

Sales from operations by industry segment and geographical area of destination are disclosed in note 35 — Segment information and information by geographical area, where revenues for 2019 and 2018 are shown restated following the design of the new macrostructure of Eni, divided in two General Departments.

Sales from operations with related parties are disclosed in note 36 — Transactions with related parties.

Other income and revenues


(€ million)	2020		2019		2018
Gains from sale of assets and businesses		10		152		454
Other proceeds		950		1,008		662
		960		1,160		1,116

Other proceeds include €357 million (€368 million in 2019) 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.

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29 Costs

Purchase, services and other charges


(€ million)	2020		2019		2018
Production costs - raw, ancillary and consumable materials and goods		21,432		36,272		41,125
Production costs - services		9,710		11,589		10,625
Lease expense and other		876		1,478		1,820
Net provisions for contingencies		349		858		1,120
Other expenses		1,317		879		1,130
		33,684		51,076		55,820
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(128)		(197)		(192)
- capitalized direct costs associated with self-constructed assets - intangible assets		(5)		(5)		(6)
		33,551		50,874		55,622

Purchase, services and other charges included geological and geophysical costs of exploration activities for €196 million (€275 million and €287 million in 2019 and 2018, respectively). In 2018, the item included operating leases for €872 million.

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 €157 million (€194 million and €197 million in 2019 and 2018, respectively).

Royalties on the extraction rights of hydrocarbons amounted to €673 million (€1,183 million and €1,043 million in 2019 and 2018, respectively).

Additions to provisions net of reversal of unused provisions mainly related to net additions for litigations amounting to €76 million (net additions of €60 million and €101 million in 2019 and 2018, respectively) and net reversals for environmental liabilities amounting to €15 million (net additions of €329 million and €266 million in 2019 and 2018, respectively). More information is provided in note 20 — 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 12 — Right-of-use assets and lease liabilities.

Payroll and related costs


(€ million)	2020		2019		2018
Wages and salaries		2,193		2,417		2,409
Social security contributions		458		449		448
Cost related to employee benefit plans		102		85		220
Other costs		239		213		170
		2,992		3,164		3,247
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(118)		(152)		(142)
- capitalized direct costs associated with self-constructed assets - intangible assets		(11)		(16)		(12)
		2,863		2,996		3,093

Other costs comprised provisions for redundancy incentives of €105 million (€45 million and €37 million in 2019 and 2018, respectively) and costs for defined contribution plans of €96 million (€99 million and €95 million in 2019 and 2018, respectively).

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Cost related to employee benefit plans are described in note 21 — 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:


(number)	2020				2019				2018
(number)	Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations
Senior managers		993		17		1,014		16		999		17
Junior managers		9,280		73		9,267		77		9,095		84
Employees		15,995		349		15,945		361		16,220		361
Workers		4,780		287		4,910		287		5,259		283
		31,048		726		31,136		741		31,573		745

The average number of employees was calculated as the average between the number of employees at the beginning and the end of the period. 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

On April 13, 2017 and on May 13, 2020, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017-2019 and 2020-2022 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 11 million of treasury shares in service of the plan 2017-2019 and 20 million in service of the plan 2020-2022.

The Long-Term Monetary Incentive plans provide for three annual awards (2017, 2018 and 2019 and 2020, 2021 and 2022, 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 2017-2019 Plan, the number of shares that will be granted at the end of the vesting period will depend: (i) for a 50%, on the market condition in terms of Total Shareholder Return (TSR) of the Eni share compared to the TSR of the FTSE Mib index of the Italian Stock Exchange Market, and to a group of Eni’s competitors (“Peer Group”)29 and the TSR of their corresponding stock exchange market30; (ii) for a 50%, on the growth in the Net Present Value (NPV) of proved reserves benchmarked against the Peer Group.

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 objective measured as the difference between the Total Shareholder Return (TSR) of Eni Shares and the TSR of the FTSE Mib Index of Italian Stock Exchange on a three-year period, adjusted with Eni’s correlation index, compared with similar differences for each company of the Eni’s group of competitors (Peer Group); (ii) for 20% on a relative parameter represented by an industrial objective measured in terms of annual unit value ($/boe) of the Net Present Value of Proven Reserves (NPV) compared with the analogous value of each company in the Peer Group, with a

The group consists of the following oil companies:Apache, BP, Chevron, ConocoPhillips, Equinor, ExxonMobil, Marathon Oil, Occidental, Royal Dutch Shell and Total.

The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition.

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final outcome equal to the average annual results over the three-year period; (iii) for 20% on an absolute parameter represented by an economic-financial objective measured as the Organic Free Cash Flow accumulated in the three-year reference period, compared to the equivalent accumulated value provided for in the first three years of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged during the performance period. The verification of CFC targets is conducted net of exogenous variables, using a gap-analysis approach approved by the Remuneration Committee, in order to assess the effective corporate performance deriving from the management action; (iv) for the remaining 35% on an environmental sustainability and energy transition objective in a three-year period consisting of three absolute objectives as follows: (a) for 15% to a decarbonisation objective measured in terms of CO2eq emissions related to Eni operated Upstream production (tCO2eq/kboe) at the end of the three-year period compared with the same value expected in the third year of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged during the performance period; (b) for 10% on an energy transition objective measured in megawatts (MW) of installed capacity of power generation from renewable sources, at the end of the three-year performance period, compared with the same value expected in the third year of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged in the performance period; (c) for 10% on a circular economy objective measured in terms of progress of three important biofuel projects at the end of the three-year performance period, compared with the progress expected in the third year of the Strategic Plan approved by the Board of Directors in the year of award and kept unchanged during the performance period.

Depending on the performance of the parameters mentioned above, the number of shares that will vest after three years may range between 0% and 180% of the initial award. Furthermore, 50% of the shares that will eventually vest is subject to a lock-up clause of one year after the vesting date.

The number of shares awarded at the grant date was: (i) 2,922,749 shares in 2020, with a weighted average fair value of €4.67 per share; (ii) 1,759,273 shares in 2019, with a weighted average fair value of €9.88 per share; (iii) 1,517,975 shares in 2018, with a weighted average fair value of €11.73 per share.

The estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plan (the stochastic method for the market condition of the plan and the Black-Scholes model for the component related to the NPV of the reserves, for the 2017-2019 Plan; the stochastic method for the 2020-2022 Plan), taking into account the fair value of the Eni share at the grant date (between € 5.885 and € 8.303 depending on the grant date in relation to the 2020 award; €13.714 per share in 2019; €14.246 per share in 2018), reduced by dividends expected along the vesting period (between 7.0% and 10.0% of the share price at vesting date in 2020; 6.1% of the share price at vesting date in 2019; 5.8% of the share price at vesting date in 2018), considering the volatility of the stock (between 41% and 44% in relation to the 2020 award; 19% for attribution 2019; 20% for attribution 2018), the forecasts for 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 2020, the costs related to the long-term monetary incentive plan, recognized as a component of the payroll cost, amounted to €7 million (€9 million in 2019; €5 million in 2018) with a contra-entry to equity reserves.

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)	2020		2019		2018
Wages and salaries		30		28		27
Post-employment benefits		2		2		2
Other long-term benefits		12		12		10
Indemnities upon termination of employment		21		12
		65		54		39

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Compensation of Directors and Statutory Auditors

Compensation of Directors amounted to €7.54 million, €9.2 million and €9.6 million in 2020, 2019 and 2018, respectively. Compensation of Statutory Auditors amounted to €0.571 million, €0.613 million and €0.604 million in 2020, 2019 and 2018, 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.

30 Finance income (expense)


(€ million)	2020		2019		2018
Finance income (expense)
Finance income		3,531		3,087		3,967
Finance expense		(4,958)		(4,079)		(4,663)
Net finance income (expense) from financial assets held for trading		31		127		32
Income (expense) from derivative financial instruments		351		(14)		(307)
		(1,045)		(879)		(971)

The analysis of finance income (expense) was as follows:


(€ million)	2020		2019		2018
Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(517)		(618)		(565)
Net finance income (expense) on financial assets held for trading		31		127		32
Interest and other expense due to banks and other financial institutions		(102)		(122)		(120)
Interest on lease liabilities		(347)		(378)
Interest from banks		10		21		18
Interest and other income on financial receivables and securities held for non-operating purposes		12		8		8
		(913)		(962)		(627)
Exchange differences		(460)		250		341
Income (expense) from derivative financial instruments		351		(14)		(307)
Other finance income (expense)
Interest and other income on financing receivables and securities held for operating purposes		97		112		132
Capitalized finance expense		73		93		52
Finance expense due to the passage of time (accretion discount)(a)		(190)		(255)		(249)
Other finance income (expense)		(3)		(103)		(313)
		(23)		(153)		(378)
		(1,045)		(879)		(971)

(a)

The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities.

Information about leases is disclosed in note 12 — Right-of-use assets and lease liabilities.

The analysis of derivative financial income (expense) is disclosed in note 23 — Derivative financial instruments and hedge accounting.

Finance income (expense) with related parties are disclosed in note 36 — Transactions with related parties.

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31 Income (expense) from investments

Share of profit (loss) of equity-accounted investments

More information is provided in note 15 — 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)	2020		2019		2018
Dividends		150		247		231
Net gain (loss) on disposals				19		22
Other net income (expense)		(75)		15		910
		75		281		1,163

Dividend income primarily related to Nigeria LNG Ltd for €113 million and to Saudi European Petrochemical Co for €28 million (€186 million, €46 million in 2019 and €187 million and €35 million in 2018).

In 2018, other net income included a gain of €889 million deriving from the business combination between Eni Norge AS and Point Resources AS, with the establishment of joint venture the Vår Energi AS, determined by the difference between the book value of the investment corresponding to the fair value of the combined net assets and the book value of the net assets sold.

32 Income taxes


(€ million)	2020		2019		2018
Current taxes:
- Italian subsidiaries		199		347		301
- subsidiaries of the Exploration & Production segment - outside Italy		1,517		4,729		4,906
- other subsidiaries - outside Italy		84		152		163
		1,800		5,228		5,370
Net deferred taxes:
- Italian subsidiaries		672		599		130
- subsidiaries of the Exploration & Production segment - outside Italy		73		(172)		497
- other subsidiaries - outside Italy		105		(64)		(27)
		850		363		600
		2,650		5,591		5,970

Current income taxes payable by Italian subsidiaries referred to foreign taxes for €169 million.

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The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (same amount in 2019 and 2018) and the effective tax charge is the following:


(€ million)	2020		2019		2018
Profit (loss) before taxation		(5,978)		5,746		10,107
Tax rate (IRES) (%)		24.0		24.0		24.0
Statutory corporation tax charge (credit) on profit or loss		(1,435)		1,379		2,426
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy		1,980		2,934		3,096
- impact pursuant to the write-down of deferred tax assets		1,785		938		261
- impact pursuant to foreign tax effects of italian entities		108		105		46
- Italian regional income tax (IRAP)		107		25		50
- effect due to the tax regime provided for intercompany dividends		96		65		47
- tax effects related to previous years		(30)		147		(24)
- other adjustments		39		(2)		68
		4,085		4,212		3,544
Effective tax charge		2,650		5,591		5,970

The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €1,777 million (€2,934 million and €3,014 million in 2019 and in 2018, respectively).

In 2020, the Group incurred income taxes, despite a pre-tax loss of €5,978 million, due to the economic crisis caused by the COVID-19 having an enduring impact on the hydrocarbons demand and by the revision of the long-term prices and of future cash flows in Eni’s activities. The lower projections of future taxable income had two impacts: the recognition of tax charges due to a write-down of deferred tax assets and a reduced capacity to recognize deferred taxes on the losses of the period.

33 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 in connection with stock-based compensation plans.

As of December 31, 2020, the shares that could be potentially issued related the estimation of new shares that will vest in connection with the 2017-2019 and 2020-2022 long-term monetary incentive plans.

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Reconciliation of the weighted average number of shares used for the calculation for both basic and diluted earnings (loss) per share was as follows:


		2020		2019		2018
Weighted average number of shares used for basic earnings (loss) per share			3,572,549,651		3,592,249,603		3,601,140,133
Potential shares to be issued for ILT incentive plan			6,465,718		2,251,406		2,782,584
Weighted average number of shares used for diluted earnings (loss) per share			3,579,015,369		3,594,501,009		3,603,922,717
Eni’s net profit (loss)	(€million)		(8,635)		148		4,126
Basic earnings (loss) per share	(€per share)		(2.42)		0.04		1.15
Diluted earnings (loss) per share	(€per share)		(2.42)		0.04		1.15

34 Exploration for evaluation of oil&gas resources


(€ million)	2020		2019		2018
Revenues related to exploration activity and evaluation				34		17
Exploration activity and evaluation costs:
- write-off of exploration and evaluation costs		314		214		93
- costs of geological and geophysical studies		196		275		287
Exploration expense for the year		510		489		380
Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs		888		1,031		1,081
Tangible assets: capitalized exploration and evaluation costs		1,341		1,563		1,267
Total tangible and intangible assets		2,229		2,594		2,348
Provision for decommissioning related to exploration activity and evaluation		93		109		77
Exploration expenditure (net cash used in investing activivties)		283		586		463
Geological and geophysical costs (cash flow from operating activities)		196		275		287
Total exploration effort		479		861		750

35 Segment information and information by geographic area

Segment information

Effective July 1, 2020, Eni’s management redesigned the macro-organizational structure of the Group, in line with its new long-term strategy, disclosed in February 2020 to the market and aimed at transforming the Company into a leader in the production and marketing of decarbonized energy products.

The new organization is based on two new General Departments:

•

Natural Resources, to build up 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 will focus its actions on the development of carbon capture and compensation projects. The General Department will incorporate the Company’s oil&gas exploration, development and production activities, natural gas wholesale via pipeline and LNG. In addition, it will include forests conservation (REDD+) and carbon storage projects. The company Eni Rewind (environmental activities), will also be consolidated in this General Department.

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•

Energy Evolution will focus on the evolution of the businesses of power generation, transformation and marketing of products from fossil to bio, blue and green. In particular, it will focus on growing power generation from renewable energy and biomethane, it will coordinate the bio and circular evolution of the Company’s refining system and chemical business, and it will further develop Eni’s retail portfolio, providing increasingly more decarbonized products for mobility, household consumption and small enterprises. The General Department will incorporate 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) and Eni gas e luce will also be consolidated in this General Department.

In re-designing the Group’s segment information for financial reporting purposes, the management evaluated that the components of the Company whose operating results are regularly reviewed by the Chief Operating Decision Maker (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 newly-established 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 new reportable segments of Eni, substantially confirming the pre-existing setup, are identified as follows:

•

Exploration & Production: research, development and production of oil, condensates and natural gas, forestry conservation (REDD+) and CO2 capture and storage projects.

•

Global Gas & LNG Portfolio (GGP): supply and sale of wholesale natural gas by 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.

•

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 activity developed by the subsidiary Eni Rewind.

Segment information presented to the CEO (i.e. the Chief Operating Decision Maker, ex IFRS 8) includes: revenues, operating profit and directly attributable assets and liabilities.

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According to the requirements of the international accounting standards regarding segment information in the event of a reorganization of business segments, the segment information for the 2019 and 2018 comparative periods have been restated for homogeneous comparison as follows.

As reported in 2019:

(€ million)	Exploration & Production		Gas & Power		Refining & Marketing and Chemicals		Corporate and Other activities		Adjustments of intragroup profits		Total
2019
Sales from operations including intersegment sales		23,572		50,015		23,334		1,681
Less: intersegment sales		(13,073)		(11,855)		(2,317)		(1,476)
Sales from operations		10,499		38,160		21,017		205				69,881
Operating profit		7,417		699		(854)		(710)		(120)		6,432
Identifiable assets(a)		68,915		9,176		12,336		1,860		(492)		91,795
Identifiable liabilities(a)		20,164		7,852		4,599		3,927		(141)		36,401
2018
Sales from operations including intersegment sales		25,744		55,690		25,216		1,589
Less: intersegment sales		(15,801)		(12,581)		(2,622)		(1,413)
Sales from operations		9,943		43,109		22,594		176				75,822
Operating profit		10,214		629		(380)		(691)		211		9,983
Identifiable assets(a)		63,051		9,989		11,692		1,171		(420)		85,483
Identifiable liabilities(a)		18,110		8,314		4,319		4,072		(275)		34,540

(a)

Include assets/liabilities directly associated with the generation of operating profit.

As restated:

(€ million)	Exploration & Production		Global Gas & LNG Portfolio		Refining & Marketing and Chemicals		Eni gas e luce, Power & Renewables		Corporate and Other activities		Adjustments of intragroup profits		Total
2019
Sales from operations including intersegment sales		23,572		11,779		42,360		8,448		1,676
Less: intersegment sales		(13,073)		(2,549)		(384)		(476)		(1,472)
Sales from operations		10,499		9,230		41,976		7,972		204				69,881
Operating profit		7,417		431		(682)		74		(688)		(120)		6,432
Identifiable assets(a)		68,915		4,092		13,569		4,068		1,643		(492)		91,795
Identifiable liabilities(a)		20,164		3,836		6,272		2,380		3,890		(141)		36,401
2018
Sales from operations including intersegment sales		25,744		14,807		46,483		8,218		1,588
Less: intersegment sales		(15,801)		(2,876)		(395)		(534)		(1,412)
Sales from operations		9,943		11,931		46,088		7,684		176				75,822
Operating profit		10,214		387		(501)		340		(668)		211		9,983
Identifiable assets(a)		63,051		4,642		13,099		4,008		1,103		(420)		85,483
Identifiable liabilities(a)		18,110		4,089		6,201		2,364		4,051		(275)		34,540

(a)

Include assets/liabilities directly associated with the generation of operating profit.

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Segment Information

(€ million)	Exploration & Production		Global Gas & LNG Portfolio		Refining & Marketing and Chemicals		Eni gas e luce, Power & Renewables		Corporate and Other activities		Adjustments of intragroup profits		Total
2020
Sales from operations including intersegment sales		13,590		7,051		25,340		7,536		1,559
Less: intersegment sales		(7,231)		(1,689)		(403)		(401)		(1,365)
Sales from operations		6,359		5,362		24,937		7,135		194				43,987
Operating profit		(610)		(332)		(2,463)		660		(563)		33		(3,275)
Net provisions for contingencies		98		64		118		(2)		26		45		349
Depreciation and amortization		(6,273)		(125)		(575)		(217)		(146)		32		(7,304)
Impairments of tangible and intangible assets and right-of-use assets		(2,170)		(2)		(1,605)		(56)		(22)				(3,855)
Reversals of tangible and intangible assets		282				334		55		1				672
Write-off of tangible and intangible assets		(322)						(7)						(329)
Share of profit (loss) of equity-accounted investments		(980)		(15)		(363)		6		(381)				(1,733)
Identifiable assets(a)		59,439		4,020		10,716		4,387		1,444		(402)		79,604
Unallocated assets(b)														30,044
Equity-accounted investments		2,680		259		2,605		217		988				6,749
Identifiable liabilities(a)		17,501		3,785		5,460		2,426		3,316		(83)		32,405
Unallocated liabilities(b)														39,750
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets		3,472		11		771		293		107		(10)		4,644
2019
Sales from operations including intersegment sales		23,572		11,779		42,360		8,448		1,676
Less: intersegment sales		(13,073)		(2,549)		(384)		(476)		(1,472)
Sales from operations		10,499		9,230		41,976		7,972		204				69,881
Operating profit		7,417		431		(682)		74		(688)		(120)		6,432
Net provisions for contingencies		97		234		276		(5)		307		(51)		858
Depreciation and amortization		(7,060)		(124)		(620)		(190)		(144)		32		(8,106)
Impairments of tangible and intangible assets and right-of-use assets		(1,347)				(1,127)		(83)		(13)				(2,570)
Reversals of tangible and intangible assets		130		5		205		41		1				382
Write-off of tangible and intangible assets		(292)				(6)		(1)		(1)				(300)
Share of profit (loss) of equity-accounted investments		7		(21)		(63)		10		(21)				(88)
Identifiable assets(a)		68,915		4,092		13,569		4,068		1,643		(492)		91,795
Unallocated assets(b)														31,645
Equity-accounted investments		4,108		346		3,107		141		1,333				9,035
Identifiable liabilities(a)		20,164		3,836		6,272		2,380		3,890		(141)		36,401
Unallocated liabilities(b)														39,139
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets		6,996		15		933		357		89		(14)		8,376
2018
Sales from operations including intersegment sales		25,744		14,807		46,483		8,218		1,588
Less: intersegment sales		(15,801)		(2,876)		(395)		(534)		(1,412)
Sales from operations		9,943		11,931		46,088		7,684		176				75,822
Operating profit		10,214		387		(501)		340		(668)		211		9,983
Net provisions for contingencies		235		53		274				579		(21)		1,120
Depreciation and amortization		(6,152)		(226)		(399)		(182)		(59)		30		(6,988)
Impairments of tangible and intangible assets		(1,025)		(6)		(193)		(50)		(18)				(1,292)
Reversals of tangible and intangible assets		299		79				48						426
Write-off of tangible and intangible assets		(97)		(1)		(2)								(100)
Share of profit (loss) of equity-accounted investments		158		(2)		(67)		11		(168)				(68)
Identifiable assets(a)		63,051		4,642		13,099		4,008		1,103		(420)		85,483
Unallocated assets(b)														32,890
Equity-accounted investments		4,972		355		275		139		1,303				7,044
Identifiable liabilities(a)		18,110		4,089		6,201		2,364		4,051		(275)		34,540
Unallocated liabilities(b)														32,760
Capital expenditure in tangible and intangible assets		7,901		26		877		238		94		(17)		9,119

(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.

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Financial information by geographical area

Identifiable assets and investments by geographical area of origin

(€ million)	Italy		Other European Union		Rest of Europe		Americas		Asia		Africa		Other areas		Total
2020
Identifiable assets(a)		17,228		4,159		3,174		4,485		16,360		33,341		857		79,604
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets		1,198		152		119		441		1,267		1,443		24		4,644
2019
Identifiable assets(a)		19,346		7,237		1,151		5,230		17,898		40,021		912		91,795
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets		1,402		306		9		1,017		1,685		3,902		55		8,376
2018
Identifiable assets(a)		18,646		7,086		1,031		4,546		16,910		36,155		1,109		85,483
Capital expenditure in tangible and intangible assets		1,424		267		538		534		1,782		4,533		41		9,119

(a)

Include assets directly associated with the generation of operating profit.

Sales from operations by geographical area of destination


(€ million)	2020		2019		2018
Italy		14,717		23,312		25,279
Other European Union		9,508		18,567		20,408
Rest of Europe		8,191		6,931		7,052
Americas		2,426		3,842		5,051
Asia		4,182		8,102		9,585
Africa		4,842		8,998		8,246
Other areas		121		129		201
		43,987		69,881		75,822

Following the exit from the European Union in 2020, revenues relating to the United Kingdom of €4,410 million for 2020 are included in the geographical area “Rest of Europe” while €6,856 million for 2019 and €6,286 million for 2018 are included in the geographical area “European Union”.

36 Transactions with related parties

In the ordinary course of its business, Eni enters into transactions regarding:

Purchase/supply of goods and services and the provision of financing to joint ventures, associates and non-consolidated subsidiaries;

Purchase/supply of goods and services to entities controlled by the Italian Government;

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. The solely non-exempted transactions, that were positively examined and valued in application of the procedure, concerned: (i) the revision of a service contract connected to network infrastructures with Vodafone Italia SpA; (ii) the renewal of a contract for the development of editorial content of World Energy magazine with Istituto Affari Internazionali. Both the counterparts are related to Eni SpA through two members of the Board of Directors;

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

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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 research initiatives, are related to the ordinary course of Eni’s business.

Transactions and balances with related parties

(€ million)	December 31, 2020						2020
Name	Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income
Joint ventures and associates
Agiba Petroleum Co		6		52						201
Angola LNG Supply Services Llc						165
Coral FLNG SA		6				1,079		49
Gas Distribution Company of Thessaloniki - Thessaly SA				13						52
Saipem Group		87		254		509		18		350
Karachaganak Petroleum Operating BV		25		141						816
Mellitah Oil & Gas BV		54		250				2		156
Petrobel Belayim Petroleum Co		65		467						556
Societa Oleodotti Meridionali SpA		3		399				20		15
Société Centrale Electrique du Congo SA		48						57
Unión Fenosa Gas SA		11		4		57		9				(3)
Vår Energi AS		39		190		456		85		1,126		(118)
Other (*)		72		24		1		66		167
		416		1,794		2,267		306		3,439		(121)
Unconsolidated entities controlled by Eni
Eni BTC Ltd						165
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		112		1		1		11
Other		5		23		10		4		9
		117		24		176		15		9
		533		1,818		2,443		321		3,448		(121)
Entities controlled by the Government
Enel Group		104		165				51		551		86
Italgas Group		1		177				3		714
Snam Group		189		211				45		1,012
Terna Group		46		62				152		225		8
GSE - Gestore Servizi Energetici		52		37				586		309		40
Other (*)		8		49				20		63
		400		701				857		2,874		134
Other related parties		1		4				2		53
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»		87		52				19		262
		1,021		2,575		2,443		1,199		6,637		13

(*)

Each individual amount included herein was lower than €50 million.

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(€ million)	December 31, 2019						2019
Name	Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income
Joint ventures and associates
Agiba Petroleum Co		3		71						229
Angola LNG Supply Services Llc						181
Coral FLNG SA		15				1,168		71
Gas Distribution Company of Thessaloniki - Thessaly SA				13						53
Saipem Group		75		227		510		27		503
Karachaganak Petroleum Operating BV		33		198				1		1,134
Mellitah Oil & Gas BV		57		171				3		365
Petrobel Belayim Petroleum Co		50		1,130				7		1,590
Unión Fenosa Gas SA		8		1		57		1		6		63
Vår Energi AS		32		143		482		63		1,481		(64)
Other (*)		106		29		1		112		87
		379		1,983		2,399		285		5,448		(1)
Unconsolidated entities controlled by Eni
Eni BTC Ltd						180
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		101		1		3		14
Other		5		25		14		6		18
		106		26		197		20		18
		485		2,009		2,596		305		5,466		(1)
Entities controlled by the Government
Enel Group		185		284				105		602		(8)
Italgas Group		3		154				1		677
Snam Group		278		229				71		1,208
Terna Group		40		45				171		223		17
GSE - Gestore Servizi Energetici		26		24				549		468		11
Other		10		19				12		35
		542		755				909		3,213		20
Other related parties		2		3				5		37
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»		75		74				33		457
		1,104		2,841		2,596		1,252		9,173		19

(*)

Each individual amount included herein was lower than €50 million.

(€ million)	December 31, 2018						2018
Name	Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income
Joint ventures and associates
Agiba Petroleum Co		1		96						156
Angola LNG Supply Services Llc						177
Coral FLNG SA		14				1,147		62
Gas Distribution Company of Thessaloniki - Thessaly SA		1		18						51
Saipem Group		75		171		793		30		420
Karachaganak Petroleum Operating BV		27		134				1		998
Mellitah Oil & Gas BV		1		268				1		502
Petrobel Belayim Petroleum Co		56		2,029				7		2,282
Unión Fenosa Gas SA		4		7		57		123				37
Vår Energi AS		13		100		218
Other (*)		44		25				111		104		(26)
		236		2,848		2,392		335		4,513		11
Unconsolidated entities controlled by Eni
Eni BTC Ltd						177
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		87		1		5		11
Other		6		23		14		7		13
		93		24		196		18		13
		329		2,872		2,588		353		4,526		11
Entities controlled by the Government
Enel Group		134		151				118		514		227
Italgas Group		5		146				23		667
Snam Group		237		289				109		1,184		(1)
Terna Group		26		47				150		231		8
GSE - Gestore Servizi Energetici		67		85				555		588		74
Other		25		18				45		34
		494		736				1,000		3,218		308
Other related parties		1		2				4		32
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»		40		140				34		229
		864		3,750		2,588		1,391		8,005		319

(*)

Each individual amount included herein was lower than €50 million.

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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 — Agip «GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for Karachaganak Petroleum Operating BV, purchase of crude oil by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs;

•

a guarantee issued on behalf of Angola LNG Supply Services Llc to cover the commitments relating to the payment of the regasification fee;

•

supply of upstream specialist services and a guarantee issued on a pro-quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant (for more information see note 27 — Guarantees, commitments and risks);

•

the acquisition of transport and distribution services from the Gas Distribution Company of Thessaloniki — Thessaly SA;

•

engineering, construction and drilling services by Saipem Group mainly for the Exploration & Production segment and residual guarantees issued by Eni SpA relating to bid bonds and performance bonds;

•

advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system at the Taranto refinery;

•

the sale of gas to Société Centrale Electrique du Congo SA;

•

a performance guarantee given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations, sale of gas and fair value of derivative financial instruments;

•

guarantees issued in compliance with contractual agreements in the interest of Vår Energi AS, the supply of upstream specialist services, the purchase of crude oil, condensates and the realized part of the forward contracts for the purchase of gas;

•

a guarantee issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd; 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:

•

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 sale with Snam Group of natural gas for granting the system balancing on the basis of prices referred to the quotations of the main energy commodities;

•

acquisition of domestic electricity transmission service 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. 249/2012; 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.

Transactions with other related parties concerned:

•

provisions to pension funds managed by Eni of €40 million; and

•

contributions and service provisions to Eni Enrico Mattei Foundation for €5 million and to Eni Foundation for €1 million.

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Financing transactions and balances with related parties

(€ million)
	December 31, 2020						2020
Name	Receivables		Payables		Guarantees		Gains		Charges
Joint ventures and associates
Angola LNG Ltd						228
Cardón IV SA		383						57
Coral FLNG SA		288						22		1
Coral South FLNG DMCC						1,304
Saipem Group		2		167						6
Société Centrale Electrique du Congo SA		83						7
Other		15		12		1		27		18
		771		179		1,533		113		25
Unconsolidated entities controlled by Eni
Other		36		28				1
		36		28				1
Entities controlled by the Government
Other				11						1
				11						1
		807		218		1,533		114		26

(€ million)
	December 31, 2019						2019
Name	Receivables		Payables		Guarantees		Gains		Charges
Joint ventures and associates
Angola LNG Ltd						249
Cardón IV SA		563		5				77
Coral FLNG SA		253								2
Coral South FLNG DMCC						1,425
Société Centrale Electrique du Congo SA		85								20
Other		18		14		2		18		14
		919		19		1,676		95		36
Unconsolidated entities controlled by Eni
Other		48		28				1
		48		28				1
Entities controlled by the Government
Other		4		12
		4		12
		971		59		1,676		96		36

(€ million)
	December 31, 2018						2018
Name	Receivables		Payables		Guarantees		Gains		Charges
Joint ventures and associates
Angola LNG Ltd						245
Cardón IV SA		705		36				95
Coral FLNG SA		108
Coral South FLNG DMCC						1,397
Shatskmorneftegaz Sàrl								7		267
Société Centrale Electrique du Congo SA		64		30						5
Vår Energi AS				494
Other		38		4		22		13		9
		915		564		1,664		115		281
Unconsolidated entities controlled by Eni
Other		49		25
		49		25
Entities controlled by the Government
Enel Group				64
Other				8						2
				72						2
		964		661		1,664		115		283

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The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

•

bank debt guarantees issued on behalf of Angola LNG Ltd;

•

the financing loan granted to Cardón IV SA for the exploration and development activities of a gas field in Venezuela;

•

the financing loan granted to Coral FLNG SA for the construction of a floating gas liquefaction plant in Area 4 offshore Mozambique (for more information see note 27 — Guarantees, commitments and risks);

•

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 27 — Guarantees, commitments and risks);

•

lease liabilities towards the Saipem group relating to multi-year contracts for the use of drilling equipment;

•

the loan granted to Société Centrale Electrique du Congo SA for the construction of a power plant in Congo.

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, 2020						December 31, 2019
	Total		Related parties		Impact %		Total		Related parties		Impact %
Other current financial assets		254		41		16.14		384		60		15.63
Trade and other receivables		10,926		802		7.34		12,873		704		5.47
Other current assets		2,686		145		5.40		3,972		219		5.51
Other non-current financial assets		1,008		766		75.99		1,174		911		77.60
Other non-current assets		1,253		74		5.91		871		181		20.78
Short-term debt		2,882		52		1.80		2,452		46		1.88
Current portion of long-term lease liabilities		849		54		6.36		889		5		0.56
Trade and other payables		12,936		2,100		16.23		15,545		2,663		17.13
Other current liabilities		4,872		452		9.28		7,146		155		2.17
Non-current lease liabilities		4,169		112		2.69		4,759		8		0.17
Other non-current liabilities		1,877		23		1.23		1,611		23		1.43

The impact of transactions with related parties on the profit and loss accounts consisted of the following:


	2020						2019						2018
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
Sales from operations		43,987		1,164		2.65		69,881		1,248		1.79		75,822		1,383		1.82
Other income and revenues		960		35		3.65		1,160		4		0.34		1,116		8		0.72
Purchases, services and other		(33,551)		(6,595)		19.66		(50,874)		(9,173)		18.03		(55,622)		(8,009)		14.40
Net (impairment losses) reversals of trade and other receivables		(226)		(6)		2.65		(432)		28		—		(415)		26		—
Payroll and related costs		(2,863)		(36)		1.26		(2,996)		(28)		0.93		(3,093)		(22)		0.71
Other operating income (expense)		(766)		13		—		287		19		6.62		129		319		—
Finance income		3,531		114		3.23		3,087		96		3.11		3,967		115		2.90
Finance expense		(4,958)		(26)		0.52		(4,079)		(36)		0.88		(4,663)		(283)		6.07

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Main cash flows with related parties are provided below:


(€ million)	2020		2019		2018
Revenues and other income		1,199		1,252		1,391
Costs and other expenses		(5,789)		(6,869)		(5,210)
Other operating (expense) income		13		19		319
Net change in trade and other receivables and payables		(136)		(839)		683
Net interests		73		81		110
Net cash provided from operating activities		(4,640)		(6,356)		(2,707)
Capital expenditure in tangible and intangible assets		(842)		(2,332)		(2,768)
Net change in accounts payable and receivable in relation to investments		(370)		(339)		20
Change in financial receivables		(160)		(241)		(566)
Net cash used in investing activities		(1,372)		(2,912)		(3,314)
Change in financial and lease liabilities		164		(817)		16
Net cash used in financing activities		164		(817)		16
Total financial flows to related parties		(5,848)		(10,085)		(6,005)

The impact of cash flows with related parties consisted of the following:


	2020						2019						2018
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
Net cash provided from operating activities		4,822		(4,640)		—		12,392		(6,356)		—		13,647		(2,707)		—
Net cash used in investing activities		(4,587)		(1,372)		29.91		(11,413)		(2,912)		25.51		(7,536)		(3,314)		43.98
Net cash used in financing activities		3,253		164		5.04		(5,841)		(817)		13.99		(2,637)		16		—

37 Other information about investments

Information on Eni’s investments as of December 31, 2020

The following section provides information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2020. 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

Ministero dell’Economia e delle Finanze

Eni SpA

Other shareholders

25.96

4.37

0.92

68.75

(#)

Company with shares quoted in the regulated market of Italy or of other EU countries

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Subsidiaries

Exploration & Production

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

%
Equity
ratio

Consolidation
or valutation
method(*)

Eni Angola SpA

San Donato
Milanese (MI)

Angola

EUR

20,200,000

Eni SpA

100.00

F.C.

Eni Mediterranea Idrocarburi SpA

Gela (CL)

Italy

EUR

5,200,000

Eni SpA

100.00

F.C.

Eni Mozambico SpA

San Donato
Milanese (MI)

Mozambique

EUR

200,000

Eni SpA

100.00

F.C.

Eni Timor Leste SpA

San Donato
Milanese (MI)

East Timor

EUR

4,386,849

Eni SpA

100.00

F.C.

Eni West Africa SpA

San Donato
Milanese (MI)

Angola

EUR

10,000,000

Eni SpA

100.00

F.C.

Floaters SpA

San Donato
Milanese (MI)

Italy

EUR

200,120,000

Eni SpA

100.00

F.C.

Ieoc SpA

San Donato
Milanese (MI)

Egypt

EUR

7,518,000

Eni SpA

100.00

F.C.

Società Petrolifera Italiana SpA

San Donato
Milanese (MI)

Italy

EUR

8,034,400

Eni SpA

Third parties

99.96

0.04

99.96

F.C.

Outside Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

%
Equity
ratio

Consolidation
or valutation
method(*)

Agip Caspian Sea BV

Amsterdam

(Netherlands)

Kazakhstan

EUR

20,005

Eni International BV

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

F.C.

Burren Energy (Bermuda)
Ltd

Hamilton

(Bermuda)

United
Kingdom

USD

12,002

Burren Energy Plc

100.00

F.C.

Burren Energy (Egypt) Ltd

London

(United
Kingdom)

Egypt

GBP

Burren Energy Plc

100.00

Eq.

Burren Energy Congo Ltd

Tortola

(British Virgin
Islands)

Republic of
the Congo

USD

50,000

Burren En.(Berm)Ltd

100.00

F.C.

Burren Energy India Ltd

London

(United
Kingdom)

United
Kingdom

GBP

Burren Energy Plc

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

F.C.

Eni Abu Dhabi BV

Amsterdam

(Netherlands)

United Arab
Emirates

EUR

20,000

Eni International BV

100.00

F.C.

Eni AEP Ltd

London

(United
Kingdom)

Pakistan

GBP

471,000

Eni UK Ltd

100.00

F.C.

Eni Albania BV

Amsterdam

(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Algeria Exploration BV

Amsterdam

(Netherlands)

Algeria

EUR

20,000

Eni International BV

100.00

F.C.

Eni Algeria Ltd Sàrl

Luxembourg

(Luxembourg)

Algeria

USD

20,000

Eni Oil Holdings BV

100.00

F.C.

Eni Algeria Production BV

Amsterdam

(Netherlands)

Algeria

EUR

20,000

Eni International BV

100.00

F.C.

Eni Ambalat Ltd

London

(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni America Ltd

Dover (USA)

USA

USD

72,000

Eni UHL Ltd

100.00

F.C.

Eni Angola Exploration BV

Amsterdam

(Netherlands)

Angola

EUR

20,000

Eni International BV

100.00

F.C.

Eni Angola Production BV

Amsterdam

(Netherlands)

Angola

EUR

20,000

Eni International BV

100.00

F.C.

Eni Argentina Exploración
y Explotación SA

Buenos Aires

(Argentina)

Argentina

ARS

205,000,000

Eni International BV

Eni Oil Holdings BV

95.00

5.00

100.00

F.C.

Eni Arguni I Ltd

London

(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

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

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Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni Australia BV

Amsterdam
(Netherlands)

Australia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Australia Ltd

London
(United
Kingdom)

Australia

GBP

20,000,000

Eni International BV

100.00

F.C.

Eni Bahrain BV

Amsterdam
(Netherlands)

Bahrain

EUR

20,000

Eni International BV

100,00

100.00

F.C.

Eni BB Petroleum Inc

Dover
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni BTC Ltd

London
(United
Kingdom)

United Kingdom

GBP

Eni International BV

100.00

Eq.

Eni Bukat Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Canada Holding Ltd

Calgary
(Canada)

Canada

USD

1,453,200,001

Eni International BV

100.00

F.C.

Eni CBM Ltd

London
(United
Kingdom)

Indonesia

USD

2,210,728

Eni Lasmo Plc

100.00

Eq.

Eni China BV

Amsterdam
(Netherlands)

China

EUR

20,000

Eni International BV

100.00

F.C.

Eni Congo SA

Pointe - Noire
(Republic
of the
Congo)

Republic
of the
Congo

USD

17,000,000

Eni E&P Holding BV

Eni Int. NA NV Sàrl

Eni International BV

99.99
(..)
(..)

100.00

F.C.

Eni Côte d’Ivoire Ltd

London
(United
Kingdom)

Ivory Coast

GBP

Eni Lasmo Plc

100.00

F.C.

Eni Cyprus Ltd

Nicosia
(Cyprus)

Cyprus

EUR

2,007

Eni International BV

100.00

F.C.

Eni Denmark BV

Amsterdam
(Netherlands)

Greenland

EUR

20,000

Eni International BV

100.00

Eq.

Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda

Rio de
Janeiro
(Brazil)

Brazil

BRL

1,593,415,000

Eni International BV

Eni Oil Holdings BV

99.99
(..)

Eq.

Eni East Ganal Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni East Sepinggan Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Elgin/Franklin Ltd

London
(United
Kingdom)

United
Kingdom

GBP

100

Eni UK Ltd

100.00

F.C.

Eni Energy Russia BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Exploration & Production Holding BV

Amsterdam
(Netherlands)

Netherlands

EUR

29,832,777.12

Eni International BV

100.00

F.C.

Eni Gabon SA

Libreville
(Gabon)

Gabon

XAF

4,000,000,000

Eni International BV

100.00

F.C.

Eni Ganal Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Gas & Power LNG Australia BV

Amsterdam
(Netherlands)

Australia

EUR

1,013,439

Eni International BV

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

F-124

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni Ghana Exploration and Production Ltd

Accra
(Ghana)

Ghana

GHS

21,412,500

Eni International BV

100.00

F.C.

Eni Hewett Ltd

Aberdeen
(United
Kingdom)

United Kingdom

GBP

3,036,000

Eni UK Ltd

100.00

F.C.

Eni Hydrocarbons Venezuela Ltd

London
(United
Kingdom)

Venezuela

GBP

8,050,500

Eni Lasmo Plc

100.00

F.C.

Eni India Ltd

London
(United
Kingdom)

India

GBP

44,000,000

Eni Lasmo Plc

100.00

Eq.

Eni Indonesia Ltd

London
(United
Kingdom)

Indonesia

GBP

100

Eni ULX Ltd

100.00

F.C.

Eni Indonesia Ots 1 Ltd

Grand Cayman
(Cayman
Islands)

Indonesia

USD

1.01

Eni Indonesia Ltd

100.00

F.C.

Eni International NA NV Sàrl

Luxembourg
(Luxembourg)

United Kingdom

USD

25,000

Eni International BV

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

F.C.

Eni Ireland BV

Amsterdam
(Netherlands)

Ireland

EUR

20,000

Eni International BV

100.00

F.C.

Eni Isatay BV

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,000

Eni International BV

100.00

F.C.

Eni JPDA 03-13 Ltd

London
(United
Kingdom)

Australia

GBP

250,000

Eni International BV

100.00

F.C.

Eni JPDA 06-105 Pty Ltd

Perth
(Australia)

Australia

AUD

80,830,576

Eni International BV

100.00

F.C.

Eni JPDA 11-106 BV

Amsterdam
(Netherlands)

Australia

EUR

50,000

Eni International BV

100.00

F.C.

Eni Kenya BV

Amsterdam
(Netherlands)

Kenya

EUR

20,000

Eni International BV

100.00

F.C.

Eni Krueng Mane Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

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

F.C.

Eni Liverpool Bay Operating Co Ltd

London
(United
Kingdom)

United Kingdom

GBP

Eni UK Ltd

100.00

Eq.

Eni LNS Ltd

London
(United
Kingdom)

United Kingdom

GBP

Eni UK Ltd

100.00

F.C.

Eni Marketing Inc

Dover
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Maroc BV

Amsterdam
(Netherlands)

Morocco

EUR

20,000

Eni International BV

100.00

F.C.

Eni México S. de RL de CV

Lomas De
Chapultepec,
Mexico City
(Mexico)

Mexico

MXN

3,000

Eni International BV

Eni Oil Holdings BV

99.90
0.10

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

F-125

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni Middle East Ltd

London
(United
Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

100.00

F.C.

Eni MOG Ltd
(in liquidation)

London
(United
Kingdom)

United
Kingdom

GBP

Eni Lasmo Plc
Eni LNS Ltd

99.99
(..)

100.00

F.C.

Eni Montenegro BV

Amsterdam
(Netherlands)

Republic of
Montenegro

EUR

20,000

Eni International BV

100.00

F.C.

Eni Mozambique Engineering Ltd

London
(United
Kingdom)

United
Kingdom

GBP

Eni Lasmo Plc

100.00

F.C.

Eni Mozambique LNG Holding BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Muara Bakau BV

Amsterdam
(Netherlands)

Indonesia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Myanmar BV

Amsterdam
(Netherlands)

Myanmar

EUR

20,000

Eni International BV

100.00

F.C.

Eni North Africa BV

Amsterdam
(Netherlands)

Libya

EUR

20,000

Eni International BV

100.00

F.C.

Eni North Ganal Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Oil & Gas Inc

Dover
(USA)

USA

USD

100,800

Eni America Ltd

100.00

F.C.

Eni Oil Algeria Ltd

London
(United
Kingdom)

Algeria

GBP

1,000

Eni Lasmo Plc

100.00

F.C.

Eni Oil Holdings BV

Amsterdam
(Netherlands)

Netherlands

EUR

450,000

Eni ULX Ltd

100.00

F.C.

Eni Oman BV

Amsterdam
(Netherlands)

Oman

EUR

20,000

Eni International BV

100.00

F.C.

Eni Pakistan Ltd

London
(United
Kingdom)

Pakistan

GBP

90,087

Eni ULX Ltd

100.00

F.C.

Eni Pakistan (M) Ltd Sàrl

Luxembourg
(Luxembourg)

Pakistan

USD

20,000

Eni Oil Holdings BV

100.00

F.C.

Eni Petroleum Co Inc

Dover
(USA)

USA

USD

156,600,000

Eni SpA
Eni International BV

63.86
36.14

100.00

F.C.

Eni Petroleum US Llc

Dover
(USA)

USA

USD

1,000

Eni BB Petroleum Inc

100.00

F.C.

Eni Portugal BV

Amsterdam
(Netherlands)

Portugal

EUR

20,000

Eni International BV

100.00

Eq.

Eni RAK BV

Amsterdam
(Netherlands)

United
Arab
Emirates

EUR

20,000

Eni International BV

100.00

F.C.

Eni Rapak Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni RD Congo SA

Kinshasa
(Democratic
Republic
of the Congo)

Democratic
Republic of
the Congo

CDF

750,000,000

Eni International BV
Eni Oil Holdings BV

99.99
(..)

Eq.

Eni Rovuma Basin BV

Amsterdam
(Netherlands)

Mozambique

EUR

20,000

Eni Mozambique
LNG H. BV

100.00

F.C.

Eni Sharjah BV

Amsterdam
(Netherlands)

United
Arab
Emirates

EUR

20,000

Eni International BV

100.00

F.C.

Eni South Africa BV

Amsterdam
(Netherlands)

Republic of
South Africa

EUR

20,000

Eni International BV

100.00

F.C.

Eni South China Sea Ltd Sàrl

Luxembourg
(Luxembourg)

China

USD

20,000

Eni International BV

100.00

Eq.

Eni TNS Ltd

Aberdeen
(United
Kingdom)

United
Kingdom

GBP

1,000

Eni UK Ltd

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

F-126

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni Tunisia BV

Amsterdam
(Netherlands)

Tunisia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Turkmenistan Ltd

Hamilton
(Bermuda)

Turkmenistan

USD

20,000

Burren En.(Berm)Ltd

100.00

F.C.

Eni UHL Ltd

London
(United
Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

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

F.C.

Eni UKCS Ltd

London
(United
Kingdom)

United
Kingdom

GBP

100

Eni UK Ltd

100.00

F.C.

Eni Ukraine Holdings BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Ukraine Llc

Kiev
(Ukraine)

Ukraine

UAH

90,765,492.19

Eni Ukraine Hold.BV
Eni International BV

99.99
0.01

Eq.

Eni Ukraine Shallow Waters BV

Amsterdam
(Netherlands)

Ukraine

EUR

20,000

Eni Ukraine Hold.BV

100.00

Eq.

Eni ULT Ltd

London
(United
Kingdom)

United
Kingdom

GBP

93,215,492.25

Eni Lasmo Plc

100.00

F.C.

Eni ULX Ltd

London
(United
Kingdom)

United
Kingdom

GBP

200,010,000

Eni ULT Ltd

100.00

F.C.

Eni US Operating Co Inc

Dover
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni USA Gas Marketing Llc

Dover
(USA)

USA

USD

10,000

Eni Marketing Inc

100.00

F.C.

Eni USA Inc

Dover
(USA)

USA

USD

1,000

Eni Oil & Gas Inc

100.00

F.C.

Eni Venezuela BV

Amsterdam
(Netherlands)

Venezuela

EUR

20,000

Eni Venezuela E&P Holding

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 Ventures Plc
(in liquidation)

London
(United
Kingdom)

United
Kingdom

GBP

Eni International BV
Eni Oil Holdings BV

99.99
(..)

Co.

Eni Vietnam BV

Amsterdam
(Netherlands)

Vietnam

EUR

20,000

Eni International BV

100.00

F.C.

Eni West Ganal Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni West Timor Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Yemen Ltd

London
(United
Kingdom)

United
Kingdom

GBP

1,000

Burren Energy Plc

100.00

Eq.

Eurl Eni Algérie

Algiers
(Algeria)

Algeria

DZD

1,000,000

Eni Algeria Ltd Sàrl

100.00

Eq.

First Calgary Petroleums LP

Wilmington
(USA)

Algeria

USD

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

Eni Canada Hold. Ltd

100.00

F.C.

Ieoc Exploration BV

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-127

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Ieoc Production BV

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

F.C.

Lasmo Sanga Sanga Ltd

Hamilton
(Bermuda)

Indonesia

USD

12,000

Eni Lasmo Plc

100.00

F.C.

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

100.00

F.C.

Liverpool Bay Ltd

London
(United
Kingdom)

United
Kingdom

USD

Eni ULX Ltd

100.00

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.

OOO ‘Eni Energhia’

Moscow
(Russia)

Russia

RUB

2,000,000

Eni Energy Russia BV
Eni Oil Holdings BV

99.90
0.10

100.00

F.C.

Zetah Congo Ltd

Nassau
(Bahamas)

Republic of the Congo

USD

300

Eni Congo SA
Burren En.Congo Ltd

66.67
33.33

Co.

Zetah Kouilou Ltd

Nassau
(Bahamas)

Republic of the Congo

USD

2,000

Eni Congo SA
Burren En.Congo Ltd
Third parties

54.50
37.00
8.50

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-128

TABLE OF CONTENTS

Global Gas & LNG Portfolio

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or 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
(former Eni Energy Activities Srl)

Rome

Italy

EUR

1,050,000

Eni SpA

100.00

F.C.

Eni Trading & Shipping SpA

Rome

Italy

EUR

60,036,650

Eni SpA

100.00

F.C.

LNG Shipping SpA

San Donato
Milanese (MI)

Italy

EUR

240,900,000

Eni SpA

100.00

F.C.

Trans Tunisian Pipeline Co SpA

San Donato
Milanese (MI)

Tunisia

EUR

1,098,000

Eni SpA

100.00

F.C.

Outside Italy

Eni G&P Trading BV

Amsterdam
(Netherlands)

Turkey

EUR

70,000

Eni International BV

100.00

F.C.

Eni Gas Liquefaction BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Société de Service du Gazoduc Transtunisien SA - Sergaz SA

Tunisi
(Tunisia)

Tunisia

TND

99,000

Eni International BV
Third parties

66.67
33.33

66.67

F.C.

Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA

Tunisi
(Tunisia)

Tunisia

TND

200,000

Eni International BV
Eni SpA
LNG Shipping SpA
Trans Tunis.P.Co SpA

99.85
0.05
0.05
0.05

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

F-129

TABLE OF CONTENTS

Refining & Marketing and Chemical

Refining & Marketing

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Ecofuel SpA

San Donato
Milanese (MI)

Italy

EUR

52,000,000

Eni SpA

100.00

F.C.

Eni4Cities SpA

San Donato
Milanese (MI)

Italy

EUR

50,000

Ecofuel SpA

100.00

Eq.

Eni Fuel SpA

Rome

Italy

EUR

58,944,310

Eni SpA

100.00

F.C.

Eni Trade & Biofuels SpA
(former Eni Energia Srl)

Rome

Italy

EUR

3,050,000

Eni SpA

100.00

F.C.

Petroven Srl

Genova

Italy

EUR

918,520

Ecofuel SpA

100.00

F.C.

Raffineria di Gela SpA

Gela (CL)

Italy

EUR

15,000,000

Eni SpA

100.00

F.C.

SeaPad SpA

Genova

Italy

EUR

12,400,000

Ecofuel SpA
Third parties

80.00
20.00

Eq.

Servizi Fondo Bombole Metano SpA

Rome

Italy

EUR

13,580,000.20

Eni SpA

100.00

Co.

Outside Italy

Eni Abu Dhabi Refining & Trading BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Abu Dhabi Refining & Trading Services BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni Abu Dhabi R&T BV

100.00

Eq.

Eni Austria GmbH

Wien
(Austria)

Austria

EUR

78,500,000

Eni International BV
Eni Deutsch.GmbH

75.00
25.00

100.00

F.C.

Eni Benelux BV

Rotterdam
(Netherlands)

Netherlands

EUR

1,934,040

Eni International BV

100.00

F.C.

Eni Deutschland GmbH

Munich
(Germany)

Germany

EUR

90,000,000

Eni International BV
Eni Oil Holdings BV

89.00
11.00

100.00

F.C.

Eni Ecuador SA

Quito
(Ecuador)

Ecuador

USD

103,142.08

Eni International BV
Esain SA

99.93
0.07

100.00

F.C.

Eni France Sàrl

Lyon
(France)

France

EUR

56,800,000

Eni International BV

100.00

F.C.

Eni Iberia SLU

Alcobendas
(Spain)

Spain

EUR

17,299,100

Eni International BV

100.00

F.C.

Eni Lubricants Trading (Shanghai) Co Ltd

Shanghai
(China)

China

EUR

5,000,000

Eni International BV

100.00

F.C.

Eni Marketing Austria GmbH

Wien
(Austria)

Austria

EUR

19,621,665.23

Eni Mineralölh.GmbH
Eni International BV

99.99
(..)

100.00

F.C.

Eni Mineralölhandel GmbH

Wien
(Austria)

Austria

EUR

34,156,232.06

Eni Austria GmbH

100.00

F.C.

Eni Schmiertechnik GmbH

Wurzburg
(Germany)

Germany

EUR

2,000,000

Eni Deutsch.GmbH

100.00

F.C.

Eni Suisse SA

Lausanne
(Switzerland)

Switzerland

CHF

102,500,000

Eni International BV

100.00

F.C.

Eni Trading & Shipping Inc

Dover
(USA)

USA

USD

36,000,000

ETS SpA

100.00

F.C.

Eni Transporte y Suministro México, S. de RL de CV

Mexico City
(Mexico)

Mexico

MXN

3,000

Eni International BV
Eni Oil Holdings BV

99.90
0.10

Eq.

Eni USA R&M Co Inc

Wilmington
(USA)

USA

USD

11,000,000

Eni International BV

100.00

Eq.

Esacontrol SA

Quito
(Ecuador)

Ecuador

USD

60,000

Eni Ecuador SA
Third parties

87.00
13.00

Eq.

Esain SA

Quito
(Ecuador)

Ecuador

USD

30,000

Eni Ecuador SA
Tecnoesa SA

99.99
(..)

100.00

F.C.

Oléoduc du Rhône SA

Valais
(Switzerland)

Switzerland

CHF

7,000,000

Eni International BV

100.00

Eq.

OOO “Eni-Nefto”

Moscow
(Russia)

Russia

RUB

1,010,000

Eni International BV
Eni Oil Holdings BV

99.01
0.99

Eq.

Tecnoesa SA

Quito
(Ecuador)

Ecuador

USD

36,000

Eni Ecuador SA
Esain SA

99.99
(..)

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-130

TABLE OF CONTENTS

Chemical

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Versalis SpA

San Donato
Milanese (MI)

Italy

EUR

1,364,790,000

Eni SpA

100.00

F.C.

Outside Italy

Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság

Budapest
(Hungary)

Hungary

HUF

4,332,947,072

Versalis SpA
Versalis Deutsc
GmbH
Versalis Int.SA

96.34
1.83
1.83

100.00

F.C.

Versalis Americas Inc

Dover
(USA)

USA

USD

100,000

Versalis
International SA

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

F.C.

Versalis Deutschland GmbH

Eschborn
(Germany)

Germany

EUR

100,000

Versalis SpA

100.00

F.C.

Versalis France SAS

Mardyck
(France)

France

EUR

126,115,582.90

Versalis SpA

100.00

F.C.

Versalis International SA

Bruxelles
(Belgium)

Belgium

EUR

15,449,173.88

Versalis SpA
Versalis Deutsc
GmbH
Dunastyr Zrt
Versalis France

59.00
23.71
14.43
2.86

100.00

F.C.

Versalis Kimya Ticaret Limited Sirketi

Istanbul
(Turkey)

Turkey

TRY

20,000

Versalis Int.SA

100.00

F.C.

Versalis México S. de R.L. de CV

Mexico City
(Mexico)

Mexico

MXN

1,000

Versalis Intern. SA
Versalis SpA

99.00
1.00

100.00

F.C.

Versalis Pacific (India) Private Ltd

Mumbai
(India)

India

INR

238,700

Versalis Sing. P. Ltd
Third parties

99.99
(..)

Eq.

Versalis Pacific Trading (Shanghai) Co
Ltd

Shanghai
(China)

China

CNY

1,000,000

Versalis SpA

100.00

F.C.

Versalis Singapore Pte Ltd

Singapore
(Singapore)

Singapore

SGD

80,000

Versalis SpA

100.00

F.C.

Versalis UK Ltd

London
(United
Kingdom)

United
Kingdom

GBP

4,004,042

Versalis SpA

100.00

F.C.

Versalis Zeal Ltd

Tokoradi
(Ghana)

Ghana

GHS

5,650,000

Versalis Intern. SA
Third parties

80.00
20.00

80.00

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-131

TABLE OF CONTENTS

Eni gas e luce, Power & Renewables

Eni gas e luce

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Eni gas e luce SpA

San Donato
Milanese (MI)

Italy

EUR

750,000,000

Eni SpA

100.00

F.C.

Evolvere Smart Srl

Milan

Italy

EUR

100,000

Evolvere Venture SpA

100.00

70.52

F.C.

Evolvere SpA Società Benefit

Milan

Italy

EUR

1,130,000

Eni gas e luce SpA
Third parties

70.52
29.48

70.52

F.C.

Evolvere Venture SpA

Milan

Italy

EUR

50,000

Evolvere SpA Soc. Ben.

100.00

70.52

F.C.

SEA SpA

L’Aquila

Italy

EUR

100,000

Eni gas e luce SpA
Third parties

60.00
40.00

60.00

F.C.

Outside Italy

Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana

Ljubljana
(Slovenia)

Slovenia

EUR

12,956,935

Eni gas e luce SpA
Third parties

51.00
49.00

51.00

F.C.

Eni Gas & Power France SA

Levallois Perret
(France)

France

EUR

29,937,600

Eni gas e luce SpA
Third parties

100.00

99.87

F.C.

Gas Supply Company Thessaloniki - Thessalia SA

Thessaloniki
(Greece)

Greece

EUR

13,761,788

Eni gas e luce SpA

100,00

100.00

F.C.

Power

In Italy

EniPower Mantova SpA

San Donato
Milanese (MI)

Italy

EUR

144,000,000

EniPower SpA
Third parties

86.50
13.50

86.50

F.C.

EniPower SpA

San Donato
Milanese (MI)

Italy

EUR

944,947,849

Eni SpA

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

F-132

TABLE OF CONTENTS

Renewables

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

CGDB Enrico Srl

San Donato
Milanese (MI)

Italy

EUR

10,000

Eni New Energy SpA

100.00

F.C.

CGDB Laerte Srl

San Donato
Milanese (MI)

Italy

EUR

10,000

Eni New Energy SpA

100.00

F.C.

Eni New Energy SpA

San Donato
Milanese (MI)

Italy

EUR

9,296,000

Eni SpA

100.00

F.C.

Wind Park Laterza Srl

San Donato
Milanese (MI)

Italy

EUR

10,000

Eni New Energy SpA

100.00

F.C.

Outside Italy

Arm Wind Llp

Nur-Sultan
(Kazakhstan)

Kazakhstan

KZT

7,963,200,000

Eni Energy Solutions BV

100.00

F.C.

Eni Energy Solutions BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni New Energy Egypt SAE

Cairo
(Egypt)

Egypt

EGP

250,000

Eni International BV
Ieoc Exploration BV
Ieoc Production BV

99.98
0.01
0.01

Eq.

Eni New Energy Pakistan (Private)
Ltd

Saddar
Town-Karachi
(Pakistan)

Pakistan

PKR

136,000,000

Eni International BV
Eni Oil Hold. BV
Eni Pakistan Ltd (M)

99.98
0.01
0.01

100.00

F.C.

Eni New Energy US Inc

Dover
(USA)

USA

USD

100

Eni Petroleum Co Inc

100.00

F.C.

Eni North Sea Wind Ltd

London
(United
Kingdom)

United
Kingdom

GBP

10,000

Eni Energy Solutions BV

100.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-133

TABLE OF CONTENTS

Corporate and Other activities

Corporate and financial companies

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Agenzia Giornalistica Italia SpA

Rome

Italy

EUR

2,000,000

Eni SpA

100.00

F.C.

D-Service Media Srl
(in liquidation)

Milan

Italy

EUR

75,000

D-Share SpA

100.00

Eq.

D-Share SpA

Milan

Italy

EUR

121,719.25

Agi SpA
Third parties

55.21
44.79

55.21

F.C.

Eni Corporate University
SpA

San Donato Milanese (MI)

Italy

EUR

3,360,000

Eni SpA

100.00

F.C.

Eni Energia Italia Srl

San Donato Milanese (MI)

Italy

EUR

50,000

Eni SpA

100.00

Co.

Eni Nuova Energia Srl

San Donato Milanese (MI)

Italy

EUR

50,000

Eni SpA

100.00

Co.

EniProgetti SpA

Venezia Marghera (VE)

Italy

EUR

2,064,000

Eni SpA

100.00

F.C.

EniServizi SpA

San Donato Milanese (MI)

Italy

EUR

13,427,419.08

Eni SpA

100.00

F.C.

Serfactoring SpA

San Donato Milanese (MI)

Italy

EUR

5,160,000

Eni SpA
Third parties

49.00
51.00

49.00

F.C.

Servizi Aerei SpA

San Donato Milanese (MI)

Italy

EUR

79,817,238

Eni SpA

100.00

F.C.

Outside Italy

Banque Eni SA

Bruxelles
(Belgium)

Belgium

EUR

50,000,000

Eni International BV
Eni Oil Holdings BV

99.90
0.10

100.00

F.C.

D-Share USA Corp.

New York
(USA)

USA

USD

0(a)

D-Share SpA

100.00

Co.

Eni Finance International
SA

Bruxelles
(Belgium)

Belgium

USD

1,480,365,336

Eni International BV
Eni SpA

66.39
33.61

100.00

F.C.

Eni Finance USA Inc

Dover
(USA)

USA

USD

15,000,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Insurance DAC

Dublin
(Ireland)

Ireland

EUR

500,000,000

Eni SpA

100.00

F.C.

Eni International BV

Amsterdam
(Netherlands)

Netherlands

EUR

641,683,425

Eni SpA

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

F.C.

EniProgetti Egypt Ltd

Cairo
(Egypt)

Egypt

EGP

50,000

Eni Progetti SpA
Eni SpA

99.00
1.00

Eq.

(*)

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.

F-134

TABLE OF CONTENTS

Joint arrangements and associates

Exploration & Production

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Mozambique Rovuma Venture SpA(†)

San Donato
Milanese (MI)

Mozambique

EUR

20,000,000

Eni SpA
Third parties

35.71
64.29

35.71

J.O.

Outside Italy

Agiba Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

Angola LNG Ltd

Hamilton
(Bermuda)

Angola

USD

9,952,000,000

Eni Angola Prod.BV
Third parties

13.60
86.40

Eq.

Ashrafi Island Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Barentsmorneftegaz Sàrl(†)

Luxembourg
(Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV
Third parties

33.33
66.67

Eq.

Cabo Delgado Gas Development Limitada(†)

Maputo
(Mozambique)

Mozambique

MZN

2,500,000

Eni Mozam.LNG H. BV
Third parties

50.00
50.00

Co.

Cardón IV SA(†)

Caracas
(Venezuela)

Venezuela

VES

172.10

Eni Venezuela BV
Third parties

50.00
50.00

Eq.

Compañia Agua Plana SA

Caracas
(Venezuela)

Venezuela

VES

0.001

Eni Venezuela BV
Third parties

26.00
74.00

Co.

Coral FLNG SA

Maputo
(Mozambique)

Mozambique

MZN

100,000,000

Eni Mozam.LNG H. BV
Third parties

25.00
75.00

Eq.

Coral South FLNG DMCC

Dubai
(United
Arab
Emirates)

United
Arab
Emirates

AED

500,000

Eni Mozam.LNG H. BV
Third parties

25.00
75.00

Eq.

East Delta Gas Co
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

37.50
62.50

Co.

East Kanayis Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

East Obaiyed Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc SpA
Third parties

50.00
50.00

Co.

El Temsah Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

El-Fayrouz Petroleum Co(†)
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

50.00
50.00

Fedynskmorneftegaz Sàrl(†)

Luxembourg
(Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV
Third parties

33.33
66.67

Eq.

Isatay Operating Company Llp(†)

Nur-Sultan
(Kazakhstan)

Kazakhstan

KZT

400,000

Eni Isatay BV
Third parties

50.00
50.00

Co.

Karachaganak Petroleum Operating
BV

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,000

Agip Karachag.BV
Third parties

29.25
70.75

Co.

Karachaganak Project Development
Ltd (KPD)
(in liquidation)

Reading,
Berkshire
(United
Kingdom)

United
Kingdom

GBP

100

Agip Karachag.BV
Third parties

38.00
62.00

Co.

Khaleej Petroleum Co Wll

Safat
(Kuwait)

Kuwait

KWD

250,000

Eni Middle E. Ltd
Third parties

49.00
51.00

Eq.

Liberty National Development Co Llc

Wilmington
(USA)

USA

USD

0(a)

Eni Oil & Gas Inc
Third parties

32.50
67.50

Eq.

Mediterranean Gas Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Meleiha Petroleum Company(†)

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.

(a)

Shares without nominal value.

F-136

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Mellitah Oil & Gas BV(†)

Amsterdam
(Netherlands)

Libya

EUR

20,000

Eni North Africa BV
Third parties

50.00
50.00

Co.

Nile Delta Oil Co Nidoco

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

37.50
62.50

Co.

Norpipe Terminal Holdco Ltd

London
(United
Kingdom)

Norway

GBP

55.69

Eni SpA
Third parties

14.20
85.80

Eq.

North Bardawil Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

30.00
70.00

North El Burg Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc SpA
Third parties

25.00
75.00

Co.

Petrobel Belayim Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

PetroBicentenario SA(†)

Caracas
(Venezuela)

Venezuela

VES

3,790

Eni Lasmo Plc
Third parties

40.00
60.00

Eq.

PetroJunín SA(†)

Caracas
(Venezuela)

Venezuela

VES

24,021

Eni Lasmo Plc
Third parties

40.00
60.00

Eq.

PetroSucre SA

Caracas
(Venezuela)

Venezuela

VES

2,203

Eni Venezuela BV
Third parties

26.00
74.00

Eq.

Pharaonic Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Point Resources FPSO AS

Sandnes
(Norway)

Norway

NOK

150,100,000

PR FPSO Holding AS

100.00

Point Resources FPSO Holding AS

Sandnes
(Norway)

Norway

NOK

60,000

Vår Energi AS

100.00

Port Said Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

PR Jotun DA

Sandnes
(Norway)

Norway

NOK

0(a)

PR FPSO AS
PR FPSO Holding AS

95.00
5.00

Raml Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

22.50
77.50

Co.

Ras Qattara Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

37.50
62.50

Co.

Rovuma Basin LNG Land Limitada(†)

Maputo
(Mozambique)

Mozambique

MZN

140,000

Mozamb. Rov. V. SpA
Third parties

33.33
66.67

Co.

Rovuma LNG Investments (DIFC)
Ltd

Dubai
(United
Arab
Emirates)

Mozambique

USD

50,000

Eni Moz. LNG H. BV
Third parties

25.00
75.00

Eq.

Rovuma LNG SA

Maputo
(Mozambique)

Mozambique

MZN

100,000,000

Eni Moz. LNG H. BV
Third parties

25.00
75.00

Eq.

Shorouk Petroleum Company

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Société Centrale Electrique du Congo SA

Pointe-Noire
(Republic
of the
Congo)

Republic
of the
Congo

XAF

44,732,000,000

Eni Congo SA
Third parties

20.00
80.00

Eq.

Société Italo Tunisienne d’Exploitation Pétrolière SA(†)

Tunisi
(Tunisia)

Tunisia

TND

5,000,000

Eni Tunisia BV
Third parties

50.00
50.00

Eq.

Sodeps – Société de Developpement
et d’Exploitation du Permis du Sud
SA(†)

Tunisi
(Tunisia)

Tunisia

TND

100,000

Eni Tunisia BV
Third parties

50.00
50.00

Co.

Thekah Petroleum Co
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

25.00
75.00

United Gas Derivatives Co

New Cairo
(Egypt)

Egypt

USD

153,000,000

Eni International BV
Third parties

33.33
66.67

Eq.

Vår Energi AS(†)

Forus
(Norway)

Norway

NOK

399,425,000

Eni International BV
Third parties

69.85
30.15

Eq.

Vår Energi Marine AS

Sandnes
(Norway)

Norway

NOK

61,000,000

Vår Energi AS

100.00

VIC CBM Ltd(†)

London
(United
Kingdom)

Indonesia

USD

52,315,912

Eni Lasmo Plc
Third parties

50.00
50.00

Eq.

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 liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

50.00
50.00

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

(a)

Shares without nominal value.

F-137

TABLE OF CONTENTS

Global Gas & LNG Portfolio

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Mariconsult SpA(†)

Milan

Italy

EUR

120,000

Eni SpA
Third parties

50.00
50.00

Eq.

Transmed SpA(†)

Milan

Italy

EUR

240,000

Eni SpA
Third parties

50.00
50.00

Eq.

Outside Italy

Angola LNG Supply Services Llc

Wilmington
(USA)

USA

USD

19,278,782

Eni USA Gas M. Llc
Third parties

13.60
86.40

Eq.

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.

GreenStream BV(†)

Amsterdam
(Netherlands)

Libya

EUR

200,000,000

Eni North Africa BV
Third parties

50.00
50.00

50.00

J.O.

Premium Multiservices SA

Tunisi
(Tunisia)

Tunisia

TND

200,000

Sergaz SA
Third parties

49.99
50.01

Eq.

SAMCO Sagl

Lugano
(Switzerland)

Switzerland

CHF

20,000

Transmed.Pip.Co Ltd
Eni International BV
Third parties

90.00
5.00
5.00

Eq.

Transmediterranean Pipeline Co Ltd(†)

St. Helier
(Jersey)

Jersey

USD

10,310,000

Eni SpA
Third parties

50.00
50.00

50.00

J.O.

Unión Fenosa Gas SA(†)

Madrid
(Spain)

Spain

EUR

32,772,000

Eni SpA
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.

(a)

Equity ratio equal to the Eni’s working interest.

F-138

TABLE OF CONTENTS

Refining & Marketing and Chemical

Refining & Marketing

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

Eni Fuel 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

Eni Fuel SpA
Third parties

25.00
75.00

Co.

Costiero Gas Livorno SpA(†)

Livorno

Italy

EUR

26,000,000

Eni Fuel SpA
Third parties

65.00
35.00

65.00

J.O.

Disma SpA

Segrate (MI)

Italy

EUR

2,600,000

Eni Fuel SpA
Third parties

25.00
75.00

Eq.

Livorno LNG Terminal SpA

Livorno

Italy

EUR

200,000

Costiero Gas Liv. SpA
Third parties

50.00
50.00

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.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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TABLE OF CONTENTS

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

1,000

Eni Abu Dhabi R&T BV
Third parties

20.00
80.00

Eq.

AET - Raffinerie beteiligungs
gesellschaft mbH(†)

Schwedt
(Germany)

Germany

EUR

27,000

Eni Deutsch.GmbH
Third parties

33.33
66.67

Eq.

Bayernoil Raffinerie gesellschaft mbH(†)

Vohburg
(Germany)

Germany

EUR

10,226,000

Eni Deutsch.GmbH
Third parties

20.00
80.00

20.00

J.O.

City Carburoil SA(†)

Rivera
(Switzerland)

Switzerland

CHF

6,000,000

Eni Suisse SA
Third parties

49.91
50.09

Eq.

Egyptian International Gas Technology Co

Cairo
(Egypt)

Egypt

EGP

100,000,000

Eni International BV
Third parties

40.00
60.00

Co.

ENEOS Italsing Pte Ltd

Singapore
(Singapore)

Singapore

SGD

12,000,000

Eni International BV
Third parties

22.50
77.50

Eq.

Fuelling Aviation Services GIE

Tremblay en France
(France)

France

EUR

Eni France Sàrl
Third parties

25.00
75.00

Co.

Mediterranée Bitumes SA

Tunisi
(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 International BV
Third parties

20.00
80.00

Eq.

Saraco SA

Meyrin
(Switzerland)

Switzerland

CHF

420,000

Eni Suisse SA
Third parties

20.00
80.00

Co.

Supermetanol CA(†)

Jose Puerto La Cruz
(Venezuela)

Venezuela

VES

120.867

Ecofuel SpA
Supermetanol CA
Third parties

34.51(a)
30.07
35.42

50.00

J.O.

TBG Tanklager
Betriebsgesellschaft GmbH(†)

Salzburg
(Austria)

Austria

EUR

43,603.70

Eni Market.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:

Ecofuel SpA
Third parties

50.00
50.00

F-140

TABLE OF CONTENTS

Chemical

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Brindisi Servizi Generali Scarl

Brindisi

Italy

EUR

1,549,060

Versalis SpA
Eni Rewind SpA
EniPower SpA
Third parties

49.00
20.20
8.90
21.90

Eq.

Finproject SpA

Morrovalle (MC)

Italy

EUR

18,500,000

Versalis SpA
Third parties

40.00
60.00

Eq.

IFM Ferrara ScpA

Ferrara

Italy

EUR

5,270,466

Versalis SpA
Eni Rewind SpA
S.E.F. Srl
Third parties

19.74
11.58
10.70
57.98

Eq.

Matrìca SpA(†)

Porto Torres (SS)

Italy

EUR

37,500,000

Versalis SpA
Third parties

50.00
50.00

Eq.

Priolo Servizi ScpA

Melilli (SR)

Italy

EUR

28,100,000

Versalis SpA
Eni Rewind SpA
Third parties

35.15
5.04
59.81

Eq.

Ravenna Servizi Industriali ScpA

Ravenna

Italy

EUR

5,597,400

Versalis SpA
EniPower SpA
Ecofuel SpA
Third parties

42.13
30.37
1.85
25.65

Eq.

Servizi Porto Marghera Scarl

Venezia Marghera (VE)

Italy

EUR

8,695,718

Versalis SpA
Eni Rewind SpA
Third parties

48.44
38.39
13.17

Eq.

Outside Italy

Lotte Versalis Elastomers Co Ltd(†)

Yeosu
(South Korea)

South Korea

KRW

501,800,000,000

Versalis SpA
Third parties

50.00
50.00

Eq.

VPM Oilfield Specialty Chemicals Llc(†)

Abu Dhabi
(United Arab
Emirates)

United Arab
Emirates

AED

1,000,000

Versalis SpA
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.

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Eni gas e luce, Power & Renewables

Eni gas e luce

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

E-Prosume Srl(†)

Milan

Italy

EUR

100,000

Evolvere Venture SpA
Third parties

50.00
50.00

Eq.

Evogy Srl

Seriate (BG)

Italy

EUR

10,000

Evolvere Venture SpA
Third parties

40.00
60.00

Eq.

PV Family Srl

Cagliari

Italy

EUR

131,200

Evolvere SpA Soc. Ben.
Third parties

23.78
76.22

Eq.

Renewable Dispatching Srl

Milan

Italy

EUR

49,000

Evolvere Venture SpA
Third parties

40.00
60.00

Eq.

Tate Srl

Bologna

Italy

EUR

408,509.29

Evolvere Venture SpA
Third parties

20.00
80.00

Eq.

Outside Italy

Gas Distribution Company of
Thessaloniki – Thessaly SA(†)

Ampelokipi-
Menemeni
(Greece)

Greece

EUR

247,127,605

Eni gas e luce SpA
Third parties

49.00
51.00

Eq.

OVO Energy (France) SAS

Paris
(France)

France

EUR

66,666.66

Eni gas e luce SpA
Third parties

25.00
75.00

Eq.

Power

In Italy

Società EniPower Ferrara Srl(†)

San Donato
Milanese (MI)

Italy

EUR

140,000,000

EniPower SpA
Third parties

51.00
49.00

51.00

J.O.

Renewables

Outside Italy

Ayla Energy Ltd(†)

London
(United
Kingdom)

United
Kingdom

USD

1,000

Eni En. Solutions BV
Third parties

50.00
50.00

Eq.

Novis Renewables Holdings Llc

Wilmington
(USA)

USA

USD

100

Eni New Energy US
Third parties

49.00
51.00

Eq.

Novis Renewables Llc(†)

Wilmington
(USA)

USA

USD

100

Eni New Energy US
Third parties

50.00
50.00

Eq.

Société Energies Renouvelables Eni-ETAP SA(†)

Tunisi
(Tunisia)

Tunisia

TND

1,000,000

Eni International BV
Third parties

50.00
50.00

Eq.

Solenova Ltd(†)

London
(United
Kingdom)

United
Kingdom

USD

1,580,000

Eni En. Solutions 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.

F-142

TABLE OF CONTENTS

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.

Saipem SpA(#) (†)

San Donato
Milanese (MI)

Italy

EUR

2,191,384,693

Eni SpA
Saipem SpA
Third parties

30.54(a)
1.73
67.73

Eq.

Outside Italy

Commonwealth Fusion Systems Llc

Wilmington
(USA)

USA

USD

215,000,514.83

Eni Next Llc
Third parties

Eq.

CZero Inc

Wilmington
(USA)

USA

USD

8,116,660.78

Eni Next Llc
Third parties

Eq.

Form Energy Inc

Sommerville
(USA)

USA

USD

124,001,561.31

Eni Next Llc
Third parties

Eq.

Tecninco Engineering Contractors Llp(†)

Aksai
(Kazakhstan)

Kazakhstan

KZT

29,478,455.00

EniProgetti SpA
Third parties

49.00
51.00

Eq.

Other activities

In Italy

Progetto Nuraghe Scarl

Porto Torres (SS)

Italy

EUR

10,000

Eni Rewind SpA
Third parties

48.55
51.45

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 in the regulated market of Italy or of other EU countries

(†)

Jointly controlled entity.

(a)

Controlling interest:

Eni SpA
Third parties

31.08
68.92

F-143

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(*)

Consorzio Universitario in Ingegneria per la Qualità e l’Innovazione

Pisa

Italy

EUR

136,000

Eni SpA
Third parties

20.00
80.00

F.V.

Outside Italy

Administradora del Golfo de Paria Este SA

Caracas
(Venezuela)

Venezuela

VES

0.001

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 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.

OPCO - Sociedade Operacional Angola LNG
SA

Luanda
(Angola)

Angola

AOA

7,400,000

Eni Angola Prod.BV
Third parties

13.60
86.40

F.V.

Petrolera Güiria SA

Caracas
(Venezuela)

Venezuela

VES

Eni Venezuela BV
Third parties

19.50
80.50

F.V.

SOMG - Sociedade de Operações e Manutenção de Gasodutos SA

Luanda
(Angola)

Angola

AOA

7,400,000

Eni Angola Prod.BV
Third parties

10.57
89.43

F.V.

Torsina Oil Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

12.50
87.50

F.V.

Global Gas & LNG Portfolio

Outside Italy

Norsea Gas GmbH

Emden
(Germany)

Germany

EUR

1,533,875.64

Eni International BV
Third parties

13.04
86.96

F.V.

(*)

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.

F-144

TABLE OF CONTENTS

Refining & Marketing and Chemical

Refining & Marketing

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

Consolidation
or valutation
method(*)

Società Italiana Oleodotti di Gaeta SpA

Rome

Italy

ITL

360,000,000

Eni SpA
Third parties

72.48
27.52

F.V.

Outside Italy

BFS Berlin Fuelling Services GbR

Hamburg
(Germany)

Germany

EUR

89,199

Eni Deutsch.GmbH
Third parties

12.50
87.50

F.V.

Compania de Economia Mixta ‘Austrogas’

Cuenca
(Ecuador)

Ecuador

USD

5,665,329

Eni Ecuador SA
Third parties

13.38
86.62

F.V.

Dépôt Pétrolier de Fos SA

Fos-Sur-Mer
(France)

France

EUR

3,954,196.40

Eni France Sàrl
Third parties

16.81
83.19

F.V.

Dépôt Pétrolier de la Côte d’Azur SAS

Nanterre
(France)

France

EUR

207,500

Eni France Sàrl
Third parties

18.00
82.00

F.V.

Joint Inspection Group Ltd

London
(United
Kingdom)

United
Kingdom

GBP

0(a)

Eni SpA
Third parties

12.50
87.50

F.V.

Saudi European Petrochemical Co
“IBN ZAHR”

Al Jubail
(Saudi Arabia)

Saudi Arabia

SAR

1,200,000,000

Ecofuel SpA
Third parties

10.00
90.00

F.V.

S.I.P.G. Société Immobilière Pétrolière de
Gestion Snc

Tremblay-En-France
(France)

France

EUR

40,000

Eni France Sàrl
Third parties

12.50
87.50

F.V.

Sistema Integrado de Gestion de Aceites Usados

Madrid
(Spain)

Spain

EUR

175,713

Eni Iberia SLU
Third parties

15.44
84.56

F.V.

Tanklager – Gesellschaft Tegel (TGT) GbR

Hamburg
(Germany)

Germany

EUR

4.953

Eni Deutsch.GmbH
Third parties

12.50
87.50

F.V.

TAR – Tankanlage Ruemlang AG

Ruemlang
(Switzerland)

Switzerland

CHF

3,259,500

Eni Suisse SA
Third parties

16.27
83.73

F.V.

Tema Lube Oil Co Ltd

Accra
(Ghana)

Ghana

GHS

258,309

Eni International BV
Third parties

12.00
88.00

F.V.

Chemical

In Italy

Novamont SpA

Novara

Italy

EUR

13,333,500

Versalis SpA
Third parties

25.00
75.00

F.V.

(*)

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.

F-145

TABLE OF CONTENTS

Information on Eni’s consolidated subsidiaries with significant non-controlling interest

In 2020 and 2019, Eni did not own any consolidated subsidiaries with a significant non-controlling interest.

Equity pertaining to minority interests as of December 31, 2020, amounted to €78 million (€61 million December 31, 2019).

Changes in the ownership interest without loss of control

In 2020, Eni did not report any changes in ownership interest without loss or acquisition of control.

In 2019, Eni acquired a 10% stake of Windirect BV.

Principal joint ventures, joint operations and associates as of December 31, 2020

Company name

Registered office

Country of
operation

Business segment

% ownership
interest

Eni’s % of
the investment

Joint venture

Vår Energi AS

Forus
(Norway)

Norway

Exploration & Production

69.85

Saipem SpA

San Donato Milanese
(MI)
(Italy)

Italy

Corporate and financial companies

30.54

31.08

Unión Fenosa Gas SA

Madrid
(Spain)

Spain

Global Gas & LNG Portfolio

50.00

Cardón IV SA

Caracas
(Venezuela)

Venezuela

Exploration & Production

50.00

Gas Distribution Company of Thessaloniki- Thessaly SA

Ampelokipi-Menemeni
(Greece)

Greece

Eni gas e luce

49.00

Joint Operation

Mozambique Rovuma Venture SpA

San Donato Milanese
(MI) (Italy)

Mozambique

Exploration & Production

35.71

GreenStream BV

Amsterdam
(Netherlands)

Libya

Global Gas & LNG Portfolio

50.00

Associates

Abu Dhabi Oil Refining Co (Takreer)

Abu Dhabi
(United Arab Emirates)

United Arab
Emirates

Refining & Marketing

20.00

Angola LNG Ltd

Hamilton
(Bermuda)

Angola

Exploration & Production

13.60

Coral FLNG SA

Maputo
(Mozambique)

Mozambique

Exploration & Production

25.00

F-147

TABLE OF CONTENTS

Main line items of profit and loss and balance sheet related to the principal joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below:


	2020
(€ million)	Vår Energi AS		Saipem SpA		Unión Fenosa Gas SA		Cardón IV SA		Gas Distribution Company of Thessaloniki -Thessaly SA		Other joint ventures
Current assets		804		6,411		599		235		31		858
- of which cash and cash equivalent		222		1,687		36				10		43
Non-current assets		16,042		4,831		717		2,040		344		924
Total assets		16,846		11,242		1,316		2,275		375		1,782
Current liabilities		189		4,903		311		262		38		1,022
- current financial liabilities		33		609		99				11		90
Non-current liabilities		15,019		3,391		501		1,615		51		333
- non-current financial liabilities		4,389		2,827		421		785		39		237
Total liabilities		15,208		8,294		812		1,877		89		1,355
Net equity		1,638		2,948		504		398		286		427
Eni’s % of the investment		69.85		31.08		50.00		50.00		49.00
Book value of the investment		1,144		908		242		199		140		188
Revenues and other income		2,450		7,408		854		612		62		286
Operating expense		(980)		(6,980)		(805)		(453)		(19)		(304)
Depreciation, amortization and impairments		(3,425)		(1,273)		(108)		(95)		(16)		(85)
Operating profit (loss)		(1,955)		(845)		(59)		64		27		(103)
Finance income (expense)		31		(166)		(29)		(98)		(1)		(21)
Income (expense) from investments				37		3
Profit (loss) before income taxes		(1,924)		(974)		(85)		(34)		26		(124)
Income taxes		603		(143)		(2)		(58)		(6)		(4)
Net profit (loss)		(1,321)		(1,117)		(87)		(92)		20		(128)
Other comprehensive income (loss)		(273)		46		(33)		(35)				(25)
Total other comprehensive income (loss)		(1,594)		(1,071)		(120)		(127)		20		(153)
Net profit (loss) attributable to Eni		(918)		(354)		(68)		(46)		10		(93)
Dividends received from the joint venture		274		3						9		10


	2019
(€ million)	Vår Energi AS		Saipem SpA		Unión Fenosa Gas SA		Cardón IV SA		Gas Distribution Company of Thessaloniki -Thessaly SA		Other joint ventures
Current assets		1,385		7,012		585		208		31		551
- of which cash and cash equivalent		182		2,272		41		6		12		40
Non-current assets		18,427		5,997		827		2,383		322		1,085
Total assets		19,812		13,009		1,412		2,591		353		1,636
Current liabilities		2,374		5,204		225		255		24		819
- current financial liabilities		33		557		49				9		165
Non-current liabilities		13,820		3,680		563		2,040		46		354
- non-current financial liabilities		3,929		3,147		493		1,140		33		274
Total liabilities		16,194		8,884		788		2,295		70		1,173
Net equity		3,618		4,125		624		296		283		463
Eni’s % of the investment		69.60		30.99		50.00		50.00		49.00
Book value of the investment		2,518		1,250		326		148		139		199
Revenues and other income		2,552		9,118		1,255		598		58		270
Operating expense		(1,015)		(7,972)		(1,221)		(456)		(16)		(277)
Depreciation, amortization and impairments		(1,208)		(690)		(53)		(86)		(14)		(47)
Operating profit (loss)		329		456		(19)		56		28		(54)
Finance income (expense)		(1)		(210)		(37)		(133)		(1)		(14)
Income (expense) from investments				(18)		6
Profit (loss) before income taxes		328		228		(50)		(77)		27		(68)
Income taxes		(258)		(130)		8		(103)		(7)		(12)
Net profit (loss)		70		98		(42)		(180)		20		(80)
Other comprehensive income (loss)		40		66		11		5
Total other comprehensive income (loss)		110		164		(31)		(175)		20		(80)
Net profit (loss) attributable to Eni		49		4		(14)		(90)		10		(40)
Dividends received from the joint venture		1,057								10		6

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Main line items of profit and loss and balance sheet related to the principal associates represented by the amounts included in the reports accounted under IFRS of each company are provided in the table below:


	2020
(€ million)	Abu Dhabi Oil Refining Co (TAKREER)		Angola LNG Ltd		Coral FLNG SA		Other associates
Current assets		1,391		618		133		623
- of which cash and cash equivalent		97		428		83		303
Non-current assets		17,938		8,633		4,777		4,072
Total assets		19,329		9,251		4,910		4,695
Current liabilities		4,897		424		172		656
- current financial liabilities		4,404		101				263
Non-current liabilities		2,757		1,187		4,186		3,068
- non-current financial liabilities		456		999		4,186		2,928
Total liabilities		7,654		1,611		4,358		3,724
Net equity		11,675		7,640		552		971
Eni’s % of the investment		20.00		13.60		25.00
Book value of the investment		2,335		1,039		138		321
Revenues and other income		11,933		976		1		954
Operating expense		(12,370)		(548)				(917)
Depreciation, amortization and impairments		(851)		(508)				(75)
Operating profit (loss)		(1,288)		(80)		1		(38)
Finance income (expense)		(91)		(96)		(11)		(13)
Income (expense) from investments								16
Profit (loss) before income taxes		(1,379)		(176)		(10)		(35)
Income taxes		4				2		(9)
Net profit (loss)		(1,375)		(176)		(8)		(44)
Other comprehensive income (loss)		(1,101)		(710)		(48)		(60)
Total other comprehensive income (loss)		(2,476)		(886)		(56)		(104)
Net profit (loss) attributable to Eni		(275)		(24)		(2)		(26)
Dividends received from the associate								13

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Supplemental oil and gas information (unaudited)

The following information prepared in accordance with “International Financial Reporting Standards” (IFRS) is presented based on the disclosure rules of the FASB Extractive Activities — Oil & 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) 2020	Italy		Rest of Europe		North Africa		Egypt		Sub Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Proved property		18,456		6,465		14,596		19,081		39,848		11,278		10,662		14,567		1,359		136,312
Unproved property		20		311		454		33		2,163		10		1,411		896		179		5,477
Support equipment and facilities		300		20		1,424		216		1,226		109		34		20		11		3,360
Incomplete wells and other		671		147		1,094		193		2,551		1,064		1,469		458		39		7,686
Gross Capitalized Costs		19,447		6,943		17,568		19,523		45,788		12,461		13,576		15,941		1,588		152,835
Accumulated depreciation, depletion and amortization		(15,565)		(5,597)		(12,793)		(12,161)		(32,248)		(2,839)		(9,003)		(12,612)		(805)		(103,623)
Net Capitalized Costs consolidated subsidiaries(a)		3,882		1,346		4,775		7,362		13,540		9,622		4,573		3,329		783		49,212
Equity-accounted entities
Proved property				11,466		68				1,384						1,833				14,751
Unproved property				2,131										11						2,142
Support equipment and facilities				23		8										6				37
Incomplete wells and other				1,566		9				17						209				1,801
Gross Capitalized Costs				15,186		85				1,401				11		2,048				18,731
Accumulated depreciation, depletion and amortization				(6,196)		(59)				(343)						(1,076)				(7,674)
Net Capitalized Costs equity-accounted entities(a)				8,990		26				1,058				11		972				11,057
2019
Consolidated subsidiaries
Proved property		17,643		6,747		15,512		20,691		43,272		12,118		11,434		15,912		1,360		144,689
Unproved property		18		323		502		34		2,361		11		1,592		979		194		6,014
Support equipment and facilities		384		21		1,549		225		1,328		116		36		23		12		3,694
Incomplete wells and other		635		103		1,362		359		2,541		1,165		1,006		457		43		7,671
Gross Capitalized Costs		18,680		7,194		18,925		21,309		49,502		13,410		14,068		17,371		1,609		162,068
Accumulated depreciation, depletion and amortization		(14,604)		(5,778)		(12,802)		(12,879)		(33,237)		(2,652)		(9,100)		(13,465)		(754)		(105,271)
Net Capitalized Costs consolidated subsidiaries(a)		4,076		1,416		6,123		8,430		16,265		10,758		4,968		3,906		855		56,797
Equity-accounted entities
Proved property				11,223		71				1,511				2		1,987				14,794
Unproved property				2,260										11						2,271
Support equipment and facilities				19		8										7				34
Incomplete wells and other				945		7				15				19		229				1,215
Gross Capitalized Costs				14,447		86				1,526				32		2,223				18,314
Accumulated depreciation, depletion and amortization				(5,287)		(61)				(323)				(20)		(1,124)				(6,815)
Net Capitalized Costs equity-accounted entities(a)(b)				9,160		25				1,203				12		1,099				11,499

(a)

The amounts include net capitalized financial charges totalling €843 million in 2020 and €878 million in 2019 for the consolidates subsidiaries and €170 million in 2020 and €166 million in 2019 for equity-accounted entities.

(b)

Includes allocation at fair value of the assets purchased by Vår Energi AS.

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Costs incurred

Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(€ million) 2020	Italy		Rest of Europe		North Africa		Egypt		Sub- Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions						55		2												57
Exploration		19		20		69		67		61		7		176		63		1		483
Development(a)		472		235		278		422		620		196		1,024		437		10		3,694
Total costs incurred consolidated subsidiaries		491		255		402		491		681		203		1,200		500		11		4,234
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration				47																47
Development(b)				1,481		3				6						14				1,504
Total costs incurred equity-accounted entities				1,528		3				6						14				1,551

2019
Consolidated subsidiaries
Proved property acquisitions								144		144
Unproved property acquisitions			135	1			23	97		256
Exploration	20	62	101	94	206	15	232	106	39	875
Development(a)	1,098	230	749	1,589	1,959	481	1,199	879	43	8,227
Total costs incurred consolidated subsidiaries	1,118	292	985	1,684	2,165	496	1,454	1,226	82	9,502
Equity-accounted entities
Proved property acquisitions		1,054								1,054
Unproved property acquisitions		1,178								1,178
Exploration		125					(1)			124
Development(b)		1,574	4		5			37		1,620
Total costs incurred equity-accounted entities(c)		3,931	4		5		(1)	37		3,976

2018
Consolidated subsidiaries
Proved property acquisitions							382			382
Unproved property acquisitions							487			487
Exploration	26	106	43	102	66	3	182	215	7	750
Development(a)	382	557	445	2,216	1,379	92	589	340	36	6,036
Total costs incurred consolidated subsidiaries	408	663	488	2,318	1,445	95	1,640	555	43	7,655
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration			2				103			105
Development(b)			3					(16)		(13)
Total costs incurred equity-accounted entities			5				103	(16)		92

(a)

Includes the abandonment costs of the assets for €516 million in 2020, €2,069 million in 2019, negative for €517 million in 2018.

(b)

Includes the abandonment costs of the assets for €424 million in 2020, €838 million in 2019, negative €22 million in 2018.

(c)

Includes allocation at fair value of the assets purchased by Vår Energi AS.

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Results of operations from oil and gas producing activities

Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to fulfil Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. Results of operations from oil and gas producing activities by geographical area consist of the following:

(€ million) 2020	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		799		334		616				2,315		788		1,333		434		1		6,620
- sales to third parties				53		1,610		2,478		784		547		179		204		109		5,964
Total revenues		799		387		2,226		2,478		3,099		1,335		1,512		638		110		12,584
Production costs		(332)		(139)		(371)		(367)		(782)		(246)		(236)		(272)		(17)		(2,762)
Transportation costs		(4)		(30)		(39)		(11)		(21)		(164)		(4)		(12)				(285)
Production taxes		(111)				(135)				(295)				(133)		(13)				(687)
Exploration expenses		(19)		(14)		(124)		(56)		(77)		(3)		(104)		(112)		(1)		(510)
D.D. & A. and Provision for abandonment(a)		(1,149)		(252)		(1,158)		(848)		(2,187)		(454)		(1,070)		(678)		(65)		(7,861)
Other income (expenses)		(255)		(45)		(360)		(204)		25		(153)		(90)		(71)		6		(1,147)
Pretax income from producing activities		(1,071)		(93)		39		992		(238)		315		(125)		(520)		33		(668)
Income taxes		219		69		(671)		(519)		(33)		(134)		(193)		86		(11)		(1,187)
Results of operations from E&P activities of consolidated subsidiaries		(852)		(24)		(632)		473		(271)		181		(318)		(434)		22		(1,855)
Equity-accounted entities
Revenues:
- sales to consolidated entities				862																862
- sales to third parties				782		10				131						307				1,230
Total revenues				1,644		10				131						307				2,092
Production costs				(350)		(7)				(23)						(18)				(398)
Transportation costs				(161)		(1)				(11)										(173)
Production taxes						(2)				(3)						(76)				(81)
Exploration expenses				(35)																(35)
D.D. & A. and Provision for abandonment				(1,163)		(1)				(69)						(50)				(1,283)
Other income (expenses)				(90)		(1)				(35)				(2)		(146)				(274)
Pretax income from producing activities				(155)		(2)				(10)				(2)		17				(152)
Income taxes				469		1										(29)				441
Results of operations from E&P activities of equity-accounted entities				314		(1)				(10)				(2)		(12)				289

(a)

Includes asset net impairment amounting to €1,865 million.

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(€ million) 2019	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		1,493		618		1,081				4,576		1,195		2,367		825		5		12,160
- sales to third parties				30		4,084		3,715		944		766		149		180		227		10,095
Total revenues		1,493		648		5,165		3,715		5,520		1,961		2,516		1,005		232		22,255
Production costs		(391)		(181)		(520)		(330)		(847)		(255)		(256)		(273)		(43)		(3,096)
Transportation costs		(5)		(31)		(60)		(10)		(39)		(158)		(4)		(15)				(322)
Production taxes		(183)				(263)				(483)				(252)		(7)		(6)		(1,194)
Exploration expenses		(25)		(51)		(30)		(10)		(90)		(39)		(170)		(31)		(43)		(489)
D.D. & A. and Provision for abandonment(a)		(944)		(201)		(839)		(978)		(3,060)		(444)		(820)		(607)		(97)		(7,990)
Other income (expenses)		(337)		(16)		(452)		(433)		(502)		(71)		(76)		(86)		(1)		(1,974)
Pretax income from producing activities		(392)		168		3,001		1,954		499		994		938		(14)		42		7,190
Income taxes		148		(11)		(2,561)		(839)		(268)		(326)		(719)		(5)		(31)		(4,612)
Results of operations from E&P activities of consolidated subsidiaries(b)		(244)		157		440		1,115		231		668		219		(19)		11		2,578
Equity-accounted entities
Revenues:
- sales to consolidated entities				1,080																1,080
- sales to third parties				677		15				207						315				1,214
Total revenues				1,757		15				207						315				2,294
Production costs				(336)		(8)				(24)						(25)				(393)
Transportation costs				(84)		(1)				(11)										(96)
Production taxes						(2)				(7)						(81)				(90)
Exploration expenses				(47)																(47)
D.D. & A. and Provision for abandonment				(722)		(1)				(70)						(51)				(844)
Other income (expenses)				(237)		(1)				(28)				(3)		(133)				(402)
Pretax income from producing activities				331		2				67				(3)		25				422
Income taxes				(179)		(2)										(54)				(235)
Results of operations from E&P activities of equity-accounted entities				152						67				(3)		(29)				187

(a)

Includes asset net impairment amounting to €1,217 million.

(b)

Results of operations exclude revenues, DD&A and income taxes associated with 3.8 million boe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause. The price collected by the buyer has been recognized as revenues in the segment information of the E&P sector prepared in accordance with IFRS and DD&A and income taxes have been accrued accordingly, because the Group performance obligation under the contract has been fulfilled and it is very likely that the buyer will not redeem its contractual right to lift within the contractual terms.

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(€ million) 2018	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		2,120		2,740		1,277				4,701		1,140		1,902		934		4		14,818
- sales to third parties				494		3,741		3,207		830		769		493		50		190		9,774
Total revenues		2,120		3,234		5,018		3,207		5,531		1,909		2,395		984		194		24,592
Production costs		(402)		(488)		(363)		(343)		(974)		(269)		(220)		(234)		(48)		(3,341)
Transportation costs		(8)		(142)		(50)		(11)		(42)		(136)		(7)		(16)				(412)
Production taxes		(171)				(243)				(435)				(191)				(6)		(1,046)
Exploration expenses		(25)		(85)		(48)		(22)		(44)		(3)		(79)		(69)		(5)		(380)
D.D. & A. and Provision for abandonment(a)		(281)		(664)		(582)		(795)		(2,490)		(387)		(941)		(594)		(67)		(6,801)
Other income (expenses)		(442)		(193)		(101)		(239)		(1,126)		(67)		(135)		(54)				(2,357)
Pretax income from producing activities		791		1,662		3,631		1,797		420		1,047		822		17		68		10,255
Income taxes		(170)		(1,070)		(2,494)		(542)		(264)		(308)		(678)		7		(26)		(5,545)
Results of operations from E&P activities of consolidated subsidiaries		621		592		1,137		1,255		156		739		144		24		42		4,710
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties						15				257				6		420				698
Total revenues						15				257				6		420				698
Production costs						(7)				(34)				(2)		(36)				(79)
Transportation costs						(1)				(28)						(2)				(31)
Production taxes						(3)				(26)						(114)				(143)
Exploration expenses				(6)										(235)						(241)
D.D. & A. and Provision for abandonment						(1)				224				(3)		(222)				(2)
Other income (expenses)				(1)		2				(27)				(25)		(122)				(173)
Pretax income from producing activities				(7)		5				366				(259)		(76)				29
Income taxes						(3)								(2)		(35)				(40)
Results of operations from E&P activities of equity-accounted entities				(7)		2				366				(261)		(111)				(11)

(a)

Includes asset net impairment amounting to €726 million.

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Proved reserves of oil and natural gas

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves comply with Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities — Oil & 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 2020, the average price for the marker Brent crude oil was $41 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 audited on a rotational basis by independent oil engineering companies31. The description of qualifications of the person primarily responsible of the reserves audit is included in the third-party audit report32.

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. 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.

In 2020, Ryder Scott Company, DeGolyer and MacNaughton provided an independent evaluation of about 36%33 of Eni’s total proved reserves as of December 31, 202034, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.

In the three-year period from 2018 to 2020, 92% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2020, the principal properties which did not undergo an independent evaluation in the last three years were Balder in Norway and Merakes in Indonesia.

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

From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018 and independent evaluation was provided also by Societé Generale de Surveillance (SGS).

See “Item 19 – Exhibits”.

The percentage of 36% increases to 37% considering the certification of A-LNG (proven reserves equal to 87 Mboe net to Eni) conducted by Gaffney Cline for the shareholders of the A-LNG Consortium (Eni 13.6%).

Including reserves of equity-accounted entities.

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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 57%, 57% and 61% of total proved reserves as of December 31, 2020, 2019 and 2018, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves associated with such contracts represented 4%, 3% and 3% of total proved reserves on an oil-equivalent basis as of December 31, 2020, 2019 and 2018, respectively.

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 3%, 4% and 4% of total proved reserves as of December 31, 2020, 2019 and 2018, respectively, on an oil equivalent basis; (ii) volumes of proved reserves of natural gas to be consumed in operations amounted to approximately 2,237 BCF at 2020 year-end (2,330 BCF and 2,470 BCF respectively at 2019 and 2018 year-end); (iii) the quantities of hydrocarbons related to the Angola LNG plant.

Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. 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, 2020 totalled 2,005 mmBOE, of which 1,064 mmBBL of liquids mainly concentrated in Africa and Asia and 4,992 BCF of natural gas particularly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 837 mmBBL of liquids and 4,703 BCF of natural gas. Changes in Eni’s 2020 proved undeveloped reserves were as follows:

(mmBOE)
Proved undeveloped reserves as of December 31, 2019					2,114
Transfer to proved developed reserves					(206)
Extensions and discoveries					40
Revisions of previous estimates					53
Improved recovery					4
Proved undeveloped reserves as of December 31, 2020					2,005

In 2020, total proved undeveloped reserves decreased by 109 mmBOE, including the effect of the update of the gas conversion rate of +18 mmBOE (proved undeveloped reserves of consolidated companies decreased by 114 mmBOE, while those of joint ventures and associates increased by 5 mmBOE).

Main changes derived from:

(i)

proved undeveloped reserves matured to proved developed reserves amounted to 206 mmBOE and were driven by progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the fields of Zohr in Egypt (79 mmBOE) and Zubair in Iraq (34 mmBOE), to the Area 1 project in Mexico (17 mmBOE), to the concession Umm Shaif/Nasr in the United Arab Emirates (16 mmBOE) and to the Karachaganak field in Kazakhstan (14 mmBOE).

(ii)

new discoveries and extensions of 40 mmBOE, of which 33 mmBBL of oil and 35 BCF of natural gas. The increase in oil reserves was driven by the FIDs made for the Breidablikk project in Norway (30 mmBOE) and the Pegasus project in the United States (3 mmBOE). The increase of 35 BCF of natural gas was due to the Mahani field in the United Arab Emirates;

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(iii)

revisions of previous estimates were positive for 53 mmBOE (which also included the update of the gas conversion rate), of which 24 mmBBL of oil and around 56 BCF of natural gas. Positive revisions of 319 mmBOE were recorded as result of higher entitlements at the oil fields of Zubair in Iraq (47 mmBOE), of Karachaganak in Kazakhstan (37 mmBOE) and of Area 1 in Mexico (32 mmboe), as well as of the progress in development activities at the Zohr gas field in Egypt (37 mmBOE), at the field Umm Shaif in the United Arab Emirates (27 mmBOE) and at the Merakes gas field in Indonesia (44 mmBOE). Negative revisions of 266 mmBOE were mainly driven by negative price effects relating to Area A and E in Libya (−41 mmBOE), Belayim and Abu Rudeis in Egypt (-45 mmBOE), by revisions related to reservoir underperformance at the fields Tuomo West in Nigeria (-33 mmBOE), Val d’Agri in Italy (-23 mmBOE), Cafc/Mle in Algeria (-15 mmBOE), Grane in Norway (-12 mmBOE), Nasr in the United Arab Emirates (-6 mmBOE), Front Runner in the United States (-6 mmBOE), M’boundi in Congo (-5 mmBOE), Blacktip in Australia (-4 mmBOE);

(iv)

improved recoveries of 4 mmBOE mainly referred to the Burun field in Turkmenistan.

Proved reserves of crude oil (including condensate and natural gas liquids)

(million barrels)
2020	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, 2019		194		41		468		264		694		746		491		225		1		3,124
of which: developed		137		37		301		149		519		682		245		148		1		2,219
undeveloped		57		4		167		115		175		64		246		77				905
Purchase of Minerals in Place
Revisions of Previous Estimates		1		1		(44)		(14)		10		100		114		16				184
Improved Recovery														5						5
Extensions and Discoveries														1		4				5
Production		(17)		(8)		(41)		(23)		(80)		(41)		(32)		(21)				(263)
Sales of Minerals in Place
Reserves at December 31, 2020		178		34		383		227		624		805		579		224		1		3,055
Equity-accounted entities
Reserves at December 31, 2019				424		12				10						31				477
of which: developed				219		12				7						31				269
undeveloped				205						3										208
Purchase of Minerals in Place
Revisions of Previous Estimates				(11)						9										(2)
Improved Recovery
Extensions and Discoveries				30																30
Production				(43)						(1)						(1)				(45)
Sales of Minerals in Place
Reserves at December 31, 2020				400		12				18						30				460
Reserves at December 31, 2020		178		434		395		227		642		805		579		254		1		3,515
Developed		146		207		255		172		484		716		297		173		1		2,451
consolidated subsidiaries		146		31		243		172		469		716		297		143		1		2,218
equity-accounted entities				176		12				15						30				233
Undeveloped		32		227		140		55		158		89		282		81				1,064
consolidated subsidiaries		32		3		140		55		155		89		282		81				837
equity-accounted entities				224						3										227

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2019	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, 2018		208		48		493		279		718		704		476		252		5		3,183
of which: developed		156		44		317		153		551		587		252		143		5		2,208
undeveloped		52		4		176		126		167		117		224		109				975
Purchase of Minerals in Place																29				29
Revisions of Previous Estimates		5		1		37		10		46		79		45		(16)		(4)		203
Improved Recovery
Extensions and Discoveries								2		21				2		9				34
Production		(19)		(8)		(62)		(27)		(90)		(37)		(32)		(20)				(295)
Sales of Minerals in Place(a)										(1)						(29)				(30)
Reserves at December 31, 2019		194		41		468		264		694		746		491		225		1		3,124
Equity-accounted entities
Reserves at December 31, 2018				297		11				12						37				357
of which: developed				154		11				8						32				205
undeveloped				143						4						5				152
Purchase of Minerals in Place				109																109
Revisions of Previous Estimates				45		2										(5)				42
Improved Recovery
Extensions and Discoveries				6																6
Production				(27)		(1)				(2)						(1)				(31)
Sales of Minerals in Place				(6)																(6)
Reserves at December 31, 2019				424		12				10						31				477
Reserves at December 31, 2019		194		465		480		264		704		746		491		256		1		3,601
Developed		137		256		313		149		526		682		245		179		1		2,488
consolidated subsidiaries		137		37		301		149		519		682		245		148		1		2,219
equity-accounted entities				219		12				7						31				269
Undeveloped		57		209		167		115		178		64		246		77				1,113
consolidated subsidiaries		57		4		167		115		175		64		246		77				905
equity-accounted entities				205						3										208

(a)

Includes 0.6 Mboe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.

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2018	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, 2017		215		360		476		280		764		766		232		162		7		3,262
of which: developed		169		219		306		203		546		547		81		144		5		2,220
undeveloped		46		141		170		77		218		219		151		18		2		1,042
Purchase of Minerals in Place														319						319
Revisions of Previous Estimates		15		6		73		21		30		(27)		(54)		23		(1)		86
Improved Recovery								7						6						13
Extensions and Discoveries										13				1		86				100
Production		(22)		(40)		(56)		(28)		(89)		(35)		(28)		(19)		(1)		(318)
Sales of Minerals in Place				(278)				(1)												(279)
Reserves at December 31, 2018		208		48		493		279		718		704		476		252		5		3,183
Equity-accounted entities
Reserves at December 31, 2017						12				12						136				160
of which: developed						12				6						25				43
undeveloped										6						111				117
Purchase of Minerals in Place				297																297
Revisions of Previous Estimates										1						(96)				(95)
Improved Recovery
Extensions and Discoveries
Production						(1)				(1)						(3)				(5)
Sales of Minerals in Place
Reserves at December 31, 2018				297		11				12						37				357
Reserves at December 31, 2018		208		345		504		279		730		704		476		289		5		3,540
Developed		156		198		328		153		559		587		252		175		5		2,413
consolidated subsidiaries		156		44		317		153		551		587		252		143		5		2,208
equity-accounted entities				154		11				8						32				205
Undeveloped		52		147		176		126		171		117		224		114				1,127
consolidated subsidiaries		52		4		176		126		167		117		224		109				975
equity-accounted entities				143						4						5				152

Main changes in proved reserves of crude oil (including condensates and natural gas liquids) reported in the tables above for the period 2018, 2019 and 2020 are discussed below.

Consolidated subsidiaries

Purchase of Minerals in Place

In 2018, purchase of proved reserves (319 mmBBL) mainly related to the entry in two Concession Agreements of Lower Zakum and Umm Shaif and Nasr in Abu Dhabi.

In 2019, purchase of proved reserves (29 mmBBL) related to the acquisition of 100% of the Oooguruk production field in Alaska.

In 2020, no purchases were made.

Revisions of Previous Estimates

In 2018, revisions of previous estimates of 86 mmBBL were mainly due to: (i) positive changes in the projects Meleiha in Egypt, Structure E in Libya and Nikaitchuq in the United States; (ii) negative changes at Karachaganak in Kazakhstan and Zubair in Iraq.

In 2019, revisions of previous estimates amounted to 203 mmBBL and were mainly due to: (i) positive revisions of 79 mmBBL in Kazakhstan in relation to the progress in development activities of the Kashagan and Karachaganak fields; (ii) positive revisions of 37 mmBBL in North Africa primarily in relation to the development of the Berkine Nord project in Algeria and, to a lesser extent, contributions from development projects in Libya; (iii) positive revisions of 46 mmBBL in the Sub-Saharan Africa in

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relation to the progress in development activities of projects in Nigeria and Angola; and (iv) 45 mmBBL of upward revisions in the rest of Asia were due to the progress of development in the Umm Shaiff and other projects in United Arab Emirates (25 mmBBL) and to entitlement effects in Iraq, Turkmenistan and Timor Leste. Upward revisions also include 6 mmBBL in Italy and Rest of Europe and 4 mmBBL in the United States. Downward revisions (total 24 mmBBL) are related to Mexico Area 1 (20 mmBBL) due to the removal of uneconomic volumes and for 4 mmBBL in Australia.

In 2020, revisions of previous estimates amounted to an increase of 184 mmBBL. Positive revisions of 100 mmBBL reported in Kazakhstan were driven by higher entitlements and progress in development activities. In the rest of Asia, positive revisions of 114 mmBBL were due to higher entitlements in Iraq (74 mmBBL) and progress at a few projects, among which the most important was the Umm Shaif/Nasr concession in the United Arab Emirates (37 mmBBL). In the Sub-Saharan Africa positive revisions of 10 mmBBL were due to higher entitlements in Nigeria (14 mmBBL), Angola (8 mmBBL), and Ghana (3 mmBBL), partly offset by negative revisions due to the debooking of the Loango and Zatchi fields reserves in Congo (-18 mmBBL). In America, positive revisions of 16 mmBBL were due to higher entitlements in Mexico (25 mmBBL), partially offset by the removal of non-economic reserves at various fields in the United States (-9 mmBBL). In Egypt, negative revisions of 14 mmBBL were mainly due to the Abu Rudeis project. In North Africa negative revisions of 44 mmBBL were driven by price effects and capital expenditures curtailments in Libya (-30 mmBBL) and Algeria (-17 mmBBL).

Improved Recovery

In 2018, improved recoveries of 13 mmBBL mainly related to Egypt and Iraq.

In 2019, no improved recoveries were reported.

In 2020, improved recoveries of 5 mmBBL related to the Burun project in Turkmenistan.

Extensions and Discoveries

In 2018, new discoveries and extensions of 100 mmBBL mainly related to the sanctioning of the final investment decision for the Area 1 project in Mexico (85 mmBBL).

In 2019, new discoveries and extensions of 34 mmBBL were driven for 21 mmBBL by the final investment decisions relating to the Assa North field in Nigeria and the Agogo field in the operated Block 15/06 offshore Angola. The remaining extensions and discoveries related to certain fields in the United States (9 mmBBL in total, relating to Nikaitchuq and Pegasus-2 fields) and 4 mmBBL in North Africa and Middle East Region driven by incremental near-field discoveries.

In 2020, new discoveries and extensions added 5 mmBBL related to the Pegasus and Front Runner fields in the United States and the Mahani field in the United Arab Emirates 78 BCF related to the final investment decision relating the Assa North field in Nigeria and 6 BCF in the United States and United Kingdom.

Sales of Minerals in Place

In 2018, the sale of 279 mmBBL related to the business combination between Eni Norge AS and Point Resources AS. The merger agreement provided for the sale of the reserves of the former subsidiary Eni Norge as part of the business combination with Point Resources and the acquisition by Eni of the interest in the reserves held by the joint venture Vår Energi, in which Eni owns a 70% stake. The merger did not produce significant effects as the reserves transferred in relation to the loss of control over the former subsidiary Eni Norge were offset by the acquisition of Eni’s interest in the reserves of the equity-accounted entity.

In 2019, the sale of 29 mmBBL related for 28 mmBBL to the sale of the entire interest in the production assets in Ecuador.

In 2020, no sales of oil properties were reported.

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Equity-accounted entities

Purchase of Minerals in Place

In 2018, purchase of 297 mmBBL related to the aforementioned merger operation in Norway leading the acquisition of the interest in Vår Energi (Eni’s interest 70%).

In 2019, purchase of 109 mmBBL related to the acquisition of assets of ExxonMobil in Norway by the joint venture Vår Energi.

In 2020, no purchases of proved reserves were made.

Revisions of Previous Estimates

In 2018, negative revisions of previous estimates for 95 mmBBL included the de-booking of proved undeveloped reserves at a project in Venezuela (-96 mmBBL) due to the deterioration of the local operating environment.

In 2019, positive revisions of previous estimates for 42 mmBBL mainly related to the Rest of Europe area (45 mmBBL) due to development activities of the Balder X project in Norway.

In 2020, negative revisions of previous estimates amounted to 2 mmBBL. In the Rest of Europe negative revisions for 11 mmBBL were reported mainly at the Ringhorne East and Ekofisk fields in Norway driven by price effects. These were partially offset by positive revisions reported in the Sub-Saharan Africa up by 9 mmBBL driven by an improved performance at the Angola LNG project.

Extensions and Discoveries

In 2018, there were no extensions or new discoveries.

In 2019, extensions and new discoveries of 6 mmBBL related to the development of the Trestakk field in Norway.

In 2020, extensions and new discoveries of 30 mmBBL were reported as a result of the final investment decision for the Bredaiblikk project in Norway.

Sales of Minerals in Place

In 2018, no sales were made.

In 2019, sales of 6 mmBBL related to the divestment of minor assets in Norway.

In 2020, no sales of proved reserves were made.

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Proved reserves of natural gas

(billion cubic feet)
2020	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, 2019		752		262		2,738		5,191		4,103		1,969		1,349		240		507		17,111
of which: developed		657		242		1,374		4,777		1,858		1,969		685		186		322		12,070
undeveloped		95		20		1,364		414		2,245				664		54		185		5,041
Purchase of Minerals in Place
Revisions of Previous Estimates		(288)		5		(259)		(65)		9		138		356		(33)				(137)
Improved Recovery
Extensions and Discoveries								6						54		4				64
Production(a)		(116)		(59)		(278)		(440)		(248)		(104)		(170)		(36)		(33)		(1,484)
Sales of Minerals in Place
Reserves at December 31, 2020		348		208		2,201		4,692		3,864		2,003		1,589		175		474		15,554
Equity-accounted entities
Reserves at December 31, 2019				772		14				287						1,648				2,721
of which: developed				597		14				88						1,648				2,347
undeveloped				175						199										374
Purchase of Minerals in Place
Revisions of Previous Estimates				(128)		1				113						(12)				(26)
Improved Recovery
Extensions and Discoveries
Production(b)				(134)		(1)				(36)						(77)				(248)
Sales of Minerals in Place
Reserves at December 31, 2020				510		14				364						1,559				2,447
Reserves at December 31, 2020		348		718		2,215		4,692		4,228		2,003		1,589		1,734		474		18,001
Developed		280		609		1,028		4,511		1,921		2,003		674		1,668		315		13,009
consolidated subsidiaries		280		194		1,014		4,511		1,751		2,003		674		109		315		10,851
equity-accounted entities				415		14				170						1,559				2,158
Undeveloped		68		109		1,187		181		2,307				915		66		159		4,992
consolidated subsidiaries		68		14		1,187		181		2,113				915		66		159		4,703
equity-accounted entities				95						194										289

(a)

It includes production volumes consumed in operations equal to 223 BCF

(b)

It includes production volumes consumed in operations equal to 16 BCF

2019	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, 2018		1,199		320		2,890		5,275		3,506		1,989		1,217		277		651		17,324
of which: developed		980		300		1,447		3,331		1,871		1,846		822		154		452		11,203
undeveloped		219		20		1,443		1,944		1,635		143		395		123		199		6,121
Purchase of Minerals in Place																7				7
Revisions of Previous Estimates		(310)		4		267		467		747		79		104		(23)		(108)		1,227
Improved Recovery
Extensions and Discoveries				2						78				274		4				358
Production(a)		(137)		(64)		(419)		(551)		(210)		(99)		(198)		(24)		(36)		(1,738)
Sales of Minerals in Place(b)										(18)				(48)		(1)				(67)
Reserves at December 31, 2019		752		262		2,738		5,191		4,103		1,969		1,349		240		507		17,111
Equity-accounted entities
Reserves at December 31, 2018				360		14				310						1,716				2,400
of which: developed				276		14				57						1,716				2,063
undeveloped				84						253										337
Purchase of Minerals in Place				405																405
Revisions of Previous Estimates				76		1				13						1				91
Improved Recovery
Extensions and Discoveries				(2)																(2)
Production(c)				(67)		(1)				(36)						(69)				(173)
Sales of Minerals in Place
Reserves at December 31, 2019				772		14				287						1,648				2,721
Reserves at December 31, 2019		752		1,034		2,752		5,191		4,390		1,969		1,349		1,888		507		19,832
Developed		657		839		1,388		4,777		1,946		1,969		685		1,834		322		14,417
consolidated subsidiaries		657		242		1,374		4,777		1,858		1,969		685		186		322		12,070
equity-accounted entities				597		14				88						1,648				2,347
Undeveloped		95		195		1,364		414		2,444				664		54		185		5,415
consolidated subsidiaries		95		20		1,364		414		2,245				664		54		185		5,041
equity-accounted entities				175						199										374

(a)

It includes production volumes consumed in operations equal to 231 BCF.

(b)

Includes 17.6 BCF as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.

(c)

It includes production volumes consumed in operations equal to 11 BCF.

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2018	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, 2017		1,131		896		3,145		4,351		3,660		2,108		1,065		225		709		17,290
of which: developed		987		771		1,233		1,421		1,693		1,878		862		171		519		9,535
undeveloped		144		125		1,912		2,930		1,967		230		203		54		190		7,755
Purchase of Minerals in Place														69						69
Revisions of Previous Estimates		138		50		219		2,238		23		(22)		81		45		(16)		2,756
Improved Recovery
Extensions and Discoveries		86								7				205		76				374
Production(a)		(156)		(162)		(474)		(445)		(184)		(97)		(201)		(43)		(42)		(1,804)
Sales of Minerals in Place				(464)				(869)						(2)		(26)				(1,361)
Reserves at December 31, 2018		1,199		320		2,890		5,275		3,506		1,989		1,217		277		651		17,324
Equity-accounted entities
Reserves at December 31, 2017						14				349						1,819				2,182
of which: developed						14				83						1,819				1,916
undeveloped										266										266
Purchase of Minerals in Place				360																360
Revisions of Previous Estimates						2				(6)						(22)				(26)
Improved Recovery
Extensions and Discoveries
Production(b)						(2)				(33)						(81)				(116)
Sales of Minerals in Place
Reserves at December 31, 2018				360		14				310						1,716				2,400
Reserves at December 31, 2018		1,199		680		2,904		5,275		3,816		1,989		1,217		1,993		651		19,724
Developed		980		576		1,461		3,331		1,928		1,846		822		1,870		452		13,266
consolidated subsidiaries		980		300		1,447		3,331		1,871		1,846		822		154		452		11,203
equity-accounted entities				276		14				57						1,716				2,063
Undeveloped		219		104		1,443		1,944		1,888		143		395		123		199		6,458
consolidated subsidiaries		219		20		1,443		1,944		1,635		143		395		123		199		6,121
equity-accounted entities				84						253										337

(a)

It includes production volumes consumed in operations equal to 222 BCF.

(b)

It includes production volumes consumed in operations equal to 8 BCF.

Main changes in proved reserves of natural gas reported in the tables above for the period 2018, 2019 and 2020 are discussed below.

Consolidated subsidiaries

Purchase of Minerals in Place

In 2018, purchase of 69 BCF essentially related to the entry in two Concession Agreements in Abu Dhabi as previously discussed.

In 2019, purchase of 7 BCF related to the Oooguruk field in Alaska.

In 2020, no purchases were made.

Revisions of Previous Estimates

In 2018, positive revisions of previous estimates of 2,756 BCF mainly related to progress in development activities in the Zohr and Nidoco NW projects in Egypt (2,238 BCF).

In 2019, positive revisions of previous estimates of 1,227 BCF mainly related to: (i) the Sub-Saharan Africa area for 747 BCF following the final investment decision for the upgrading of the LNG Bonny project in Nigeria (Eni’s interest 10.4%); (ii) Egypt for 467 BCF following the progress in development activities of the Zohr field and other minor projects; (iii) upward revisions of 267 BCF were reported in North Africa and were mainly driven by progress in the development at Berkine North fields in Algeria (227 BCF), while the remaining volumes related to the progress of activities in Lybia and other fields in Algeria; (iv) in Kazakhstan we recorded upward revisions of 79 BCF due to better field performance; (v) in the Rest of Asia the upward revisions related to Pakistan (23 BCF relating to over nine fields), United Arab Emirates (13 BCF in three fields), Indonesia at the Jangkrik field (15 BCF) and Iraq at the Zubair Field (15 BCF) mainly driven by progress in development activities. Other revisions for 11 BCF were recorded in United Kingdom and United States.

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In 2020, revisions of previous estimates were a net negative of 137 BCF. In Italy, 288 BCF of negative revisions were reported mainly at the Hera Lacina-Linda, Cervia-Arianna, Luna, Annamaria, Val d’Agri and Porto Garibaldi-Agostino projects and other gas fields in the Adriatic sea due to price effects. In North Africa, 259 BCF of negative revisions were driven by price effects in Libya (-287 BCF) in particular at Bahr Essalam and Area E fields and in various fields in Algeria (+18 BCF). In Egypt, 65 BCF of negative revisions were recorded at Tuna due to performance revision and at Zohr field due to price effect. In America, 33 BCF of negative revision were due to price effects at various US gas fields (−78 BCF), mainly Alliance fields, partially offset by Area 1 in Mexico (46 BCF).

Revisions were positive for 356 BCF in the Rest of Asia driven by a better performance at the Merakes projects in Indonesia (227 BCF) and at the Zubair field in Iraq (97 BCF) due to improved production expectations. In Kazakhstan, positive revisions of 138 BCF were reported at the Karachaganak project due to technical appraisal and higher entitlements.

Improved Recovery

In 2018, 2019 and 2020, no material improved recoveries were recorded.

Extensions and Discoveries

In 2018, new discoveries and extensions of 374 BCF essentially related to: (i) Rest of Asia (205 BCF) mainly following to the final investment decision for the Merakes project in Indonesia; (ii) Italy (86 BCF) mainly due to the final investment decision for the Argo and Cassiopea projects; and (iii) America (76 BCF) due to the final investment decision for the Area 1 operated project in Mexico.

In 2019, new discoveries and extensions of 358 BCF mainly related to the Rest of Asia (274 BCF) following to the final investment decision for the Udr-Ghasha project in the offshore of the United Arab Emirates.

In 2020, new discoveries and extensions of 64 BCF mainly related to the Rest of Asia (with an upward revision of 54 BCF) following the final investment decision for the Mahani field in the United Arab Emirates, with production started-up in January 2021, and Egypt for the near-field discoveries in the Bashrush and Abu Madi West concessions.

Sales of Minerals in Place

In 2018, sales of 1,361 BCF mainly related to: (i) Egypt (869 BCF) following the sale of 10% of the Zohr project to Mubadala Petroleum; and (ii) Rest of Europe (464 BCF) mainly following the sale of assets in Croatia and the effects of the aforementioned business combination in Norway.

In 2019, sales of 67 BCF mainly related to the Rest of Asia area (48 BCF) following the sale of the 20% stake in the Merakes discovery in Indonesia.

In 2020, no sales were made.

Equity-accounted entities

Purchase of Minerals in Place

In 2018, purchase of 360 BCF related to the aforementioned merger operation in Norway leading the acquisition of the interest in Vår Energi.

In 2019, purchase of 405 BCF related to the acquisition of assets of ExxonMobil in Norway by the joint venture Vår Energi.

In 2020, no purchases were made.

Revisions of Previous Estimates

In 2018, negative revisions of previous estimates of 26 BCF mainly related to the de-booking of reserves in Venezuela, already mentioned above.

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In 2019, positive revisions of previous estimates of 91 BCF essentially related to the Rest of Europe (76 BCF) following the progress in the Balder X project and the Snorre and Smørbukk fields in Norway.

In 2020, negative revisions of previous estimates of 26 BCF essentially related to the Rest of Europe (128 BCF) mainly in relation to the Grane and Midgard projects in Norway. In Sub-Saharan Africa, 113 BCF of positive revisions were reported at the Angola LNG project due to a better performance.

Extensions and Discoveries

In 2018, 2019 and 2020, there were no extensions or new relevant discoveries.

Sales of Minerals in Place

In 2018, 2019 sales were not material in Rest of Asia and Europe, respectively, while in 2020 no sales were made.

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 & 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.

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The standardized measure of discounted future net cash flows by geographical area consists of the following:

(€ million)
December 31, 2020	Italy		Rest of Europe		North Africa		Egypt		Sub- Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Future cash inflows		6,120		1,737		19,780		26,003		26,901		21,519		22,528		6,638		1,599		132,825
Future production costs		(3,587)		(753)		(5,431)		(7,515)		(10,909)		(6,224)		(7,241)		(3,382)		(265)		(45,307)
Future development and abandonment costs		(1,925)		(756)		(4,378)		(1,638)		(4,257)		(1,743)		(4,511)		(1,786)		(246)		(21,240)
Future net inflow before income tax		608		228		9,971		16,850		11,735		13,552		10,776		1,470		1,088		66,278
Future income tax		(170)		(61)		(4,946)		(5,320)		(2,988)		(2,313)		(6,774)		(441)		(140)		(23,153)
Future net cash flows		438		167		5,025		11,530		8,747		11,239		4,002		1,029		948		43,125
10% discount factor		(33)		108		(2,413)		(4,101)		(3,714)		(6,040)		(1,681)		(482)		(383)		(18,739)
Standardized measure of discounted future net cash flows		405		275		2,612		7,429		5,033		5,199		2,321		547		565		24,386
Equity-accounted entities
Future cash inflows				15,306		251				1,253						6,291				23,101
Future production costs				(5,942)		(98)				(982)						(1,641)				(8,663)
Future development and abandonment costs				(6,244)		(29)				(46)						(137)				(6,456)
Future net inflow before income tax				3,120		124				225						4,513				7,982
Future income tax				(576)		(54)				(3)						(1,375)				(2,008)
Future net cash flows				2,544		70				222						3,138				5,974
10% discount factor				(1,055)		(43)				(110)						(1,460)				(2,668)
Standardized measure of discounted future net cash flows				1,489		27				112						1,678				3,306
Total consolidated subsidiaries and equity-accounted entities		405		1,764		2,639		7,429		5,145		5,199		2,321		2,225		565		27,692

December 31, 2019	Italy		Rest of Europe		North Africa		Egypt		Sub- Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Future cash inflows		12,363		3,268		38,083		37,020		48,778		36,435		31,220		11,378		1,686		220,231
Future production costs		(5,078)		(1,175)		(6,944)		(10,934)		(15,534)		(8,239)		(8,888)		(5,060)		(293)		(62,145)
Future development and abandonment costs		(3,551)		(1,338)		(4,985)		(1,591)		(6,265)		(2,362)		(6,047)		(2,629)		(225)		(28,993)
Future net inflow before income tax		3,734		755		26,154		24,495		26,979		25,834		16,285		3,689		1,168		129,093
Future income tax		(796)		(249)		(13,632)		(7,829)		(9,926)		(5,485)		(11,379)		(1,034)		(143)		(50,473)
Future net cash flows		2,938		506		12,522		16,666		17,053		20,349		4,906		2,655		1,025		78,620
10% discount factor		(466)		63		(5,852)		(5,822)		(6,604)		(10,832)		(1,990)		(1,187)		(443)		(33,133)
Standardized measure of discounted future net cash flows		2,472		569		6,670		10,844		10,449		9,517		2,916		1,468		582		45,487
Equity-accounted entities
Future cash inflows				25,094		380				1,787						7,730				34,991
Future production costs				(6,953)		(113)				(863)						(2,038)				(9,967)
Future development and abandonment costs				(6,519)		(23)				(59)						(145)				(6,746)
Future net inflow before income tax				11,622		244				865						5,547				18,278
Future income tax				(7,020)		(77)				(225)						(1,783)				(9,105)
Future net cash flows				4,602		167				640						3,764				9,173
10% discount factor				(1,544)		(88)				(322)						(1,809)				(3,763)
Standardized measure of discounted future net cash flows				3,058		79				318						1,955				5,410
Total consolidated subsidiaries and equity-accounted entities		2,472		3,627		6,749		10,844		10,767		9,517		2,916		3,423		582		50,897

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December 31, 2018	Italy		Rest of Europe		North Africa		Egypt		Sub- Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Future cash inflows		18,372		4,895		43,578		39,193		53,534		40,698		33,384		14,192		2,319		250,165
Future production costs		(5,659)		(1,438)		(6,653)		(12,193)		(16,417)		(8,276)		(9,492)		(6,038)		(511)		(66,677)
Future development and abandonment costs		(4,670)		(1,350)		(4,700)		(2,769)		(6,778)		(2,640)		(5,755)		(2,467)		(291)		(31,420)
Future net inflow before income tax		8,043		2,107		32,225		24,231		30,339		29,782		18,137		5,687		1,517		152,068
Future income tax		(1,671)		(798)		(17,514)		(7,829)		(11,566)		(6,524)		(11,980)		(1,791)		(289)		(59,962)
Future net cash flows		6,372		1,309		14,711		16,402		18,773		23,258		6,157		3,896		1,228		92,106
10% discount factor		(2,045)		(124)		(6,727)		(6,564)		(7,501)		(12,477)		(2,258)		(1,508)		(491)		(39,695)
Standardized measure of discounted future net cash flows		4,327		1,185		7,984		9,838		11,272		10,781		3,899		2,388		737		52,411
Equity-accounted entities
Future cash inflows				18,608		347				2,675						8,292				29,922
Future production costs				(4,686)		(138)				(873)						(2,192)				(7,889)
Future development and abandonment costs				(3,633)		(3)				(75)						(191)				(3,902)
Future net inflow before income tax				10,289		206				1,727						5,909				18,131
Future income tax				(6,822)		(43)				(204)						(1,839)				(8,908)
Future net cash flows				3,467		163				1,523						4,070				9,223
10% discount factor				(1,104)		(76)				(793)						(2,009)				(3,982)
Standardized measure of discounted future net cash flows				2,363		87				730						2,061				5,241
Total consolidated subsidiaries and equity-accounted entities		4,327		3,548		8,071		9,838		12,002		10,781		3,899		4,449		737		57,652

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, 2020, 2019 and 2018, are as follows:

(€ million)
2020	Consolidated s ubsidiaries		Equity- accounted entities		Total
Standardized measure of discounted future net cash flows at December 31, 2019		45,487		5,410		50,897
Increase (Decrease):
- sales, net of production costs		(10,046)		(1,490)		(11,536)
- net changes in sales and transfer prices, net of production costs		(34,188)		(5,324)		(39,512)
- extensions, discoveries and improved recovery, net of future production and development costs		123		142		265
- changes in estimated future development and abandonment costs		792		(834)		(42)
- development costs incurred during the period that reduced future development costs		4,147		1,192		5,339
- revisions of quantity estimates		36		(285)		(249)
- accretion of discount		7,136		1,065		8,201
- net change in income taxes		13,336		3,814		17,150
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other		(2,437)		(384)		(2,821)
Net increase (decrease)		(21,101)		(2,104)		(23,205)
Standardized measure of discounted future net cash flows at December 31, 2020		24,386		3,306		27,692

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TABLE OF CONTENTS

2019	Consolidated subsidiaries		Equity- accounted entities		Total
Standardized measure of discounted future net cash flows at December 31, 2018		52,411		5,241		57,652
Increase (Decrease):
- sales, net of production costs		(18,236)		(1,675)		(19,911)
- net changes in sales and transfer prices, net of production costs		(14,972)		(2,247)		(17,219)
- extensions, discoveries and improved recovery, net of future production and development costs		1,240		86		1,326
- changes in estimated future development and abandonment costs		(1,157)		(916)		(2,073)
- development costs incurred during the period that reduced future development costs		5,128		687		5,815
- revisions of quantity estimates		5,573		1,377		6,950
- accretion of discount		8,666		1,050		9,716
- net change in income taxes		6,013		(761)		5,252
- purchase of reserves in-place		260		2,579		2,839
- sale of reserves in-place(a)		(429)		(88)		(517)
- changes in production rates (timing) and other		990		77		1,067
Net increase (decrease)		(6,924)		169		(6,755)
Standardized measure of discounted future net cash flows at December 31, 2019		45,487		5,410		50,897

(a)

Includes volume as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.

2018	Consolidated subsidiaries		Equity- accounted entities		Total
Standardized measure of discounted future net cash flows at December 31, 2017		36,993		2,633		39,626
Increase (Decrease):
- sales, net of production costs		(19,793)		(445)		(20,238)
- net changes in sales and transfer prices, net of production costs		27,970		671		28,641
- extensions, discoveries and improved recovery, net of future production and development costs		1,649				1,649
- changes in estimated future development and abandonment costs		(2,525)		216		(2,309)
- development costs incurred during the period that reduced future development costs		6,468		14		6,482
- revisions of quantity estimates		10,487		(803)		9,684
- accretion of discount		5,670		384		6,054
- net change in income taxes		(16,566)		193		(16,373)
- purchase of reserves in-place		5,369		6,700		12,069
- sale of reserves in-place		(8,363)				(8,363)
- changes in production rates (timing) and other		5,052		(4,322)		730
Net increase (decrease)		15,418		2,608		18,026
Standardized measure of discounted future net cash flows at December 31, 2018		52,411		5,241		57,652

F-170

						Page
	Certain defined terms					ii
	Presentation of financial and other information					ii
	Statements regarding competitive position					ii
	Glossary					iii
	Abbreviations and conversion table					viii
	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
	Selected Financial Information					1
	Selected Operating Information					3
	Risk factors					5
	Item 4. INFORMATION ON THE COMPANY					29
	History and development of the Company					29
	BUSINESS OVERVIEW					40
	Exploration & Production					40
	Global Gas & LNG Portfolio					66
	Refining & Marketing and Chemicals					69
	Eni gas e luce, Power & Renewables					76
	Corporate and Other activities					79
	Research and development					79
	Insurance					81
	Environmental matters					81
	Regulation of Eni’s businesses					89
	Property, plant and equipment					96
	Organizational structure					96
	Item 4A. UNRESOLVED STAFF COMMENTS					96
	Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS					97
	Executive summary					97
	Critical accounting estimates					105
	Group results of operations					106
	Liquidity and capital resources					115
	Recent developments					120
	Management’s expectations of operations					120
	Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES					129
	Directors and Senior Management					129
	Compensation					139
	Board practices					139
	Employees					151
	Share ownership					152
	Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS					153
	Major Shareholders					153
	Related party transactions					153
	Item 8. FINANCIAL INFORMATION					153
	Consolidated Statements and other financial information					153
	Significant changes					155
	Item 9. THE OFFER AND THE LISTING					155
	Offer and listing details					155
	Markets					156
	Item 10. ADDITIONAL INFORMATION					157
	Memorandum and Articles of Association					157
	Material contracts					164
	Exchange controls					164
	Taxation					164
	Documents on display					169
	Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK					169
	Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES					172
	Item 12A. Debt securities					172
	Item 12B. Warrants and rights					172
	Item 12C. Other securities					172
	Item 12D. American Depositary Shares					172
	PART II
	Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES					174
	Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS					174
	Item 15. CONTROLS AND PROCEDURES					174
	Item 16. [RESERVED]					175
	Item 16A. Board of Statutory Auditors financial expert					175
	Item 16B. Code of Ethics					175
	Item 16C. Principal accountant fees and services					175
	Item 16D. Exemptions from the Listing Standards for Audit Committees					176
	Item 16E. Purchases of equity securities by the issuer and affiliated purchasers					177
	Item 16F. Change in Registrant’s Certifying Accountant					177
	Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual					177
	Item 16H. Mine safety disclosure					179
	PART III
	Item 17. FINANCIAL STATEMENTS					180
	Item 18. FINANCIAL STATEMENTS					180
	Item 19. EXHIBITS					180

	Page
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheet as of December 31, 2020 and December 31, 2019		F-5
Consolidated profit and loss account for the years ended December 31, 2020, 2019 and 2018		F-6
Consolidated Statements of comprehensive income for the years ended December 31, 2020, 2019 and 2018		F-7
Consolidated Statements of changes in shareholders’ equity for the years ended December 31, 2020, 2019 and 2018		F-8
Consolidated Statement of cash flows for the years ended December 31, 2020, 2019 and 2018		F-11
Notes on Consolidated Financial Statements		F-15

	1.			By-laws of Eni SpA
	2.			Description of securities registered under Section 12 of the Exchange Act (incorporated by reference to Exhibit 2 to Form 20-F 2019 (File No. 001-14090) filed on April 2, 2020)
	8.			List of subsidiaries (see Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements)
	11.			Code of Ethics (incorporated by reference to Exhibit 11 to Form 20-F 2019 (File No. 001-14090) filed on April 2, 2020)
	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 2020 incorporated herein by reference
	15.a(ii)			Report of DeGolyer and MacNaughton
	15.a(iii)			Report of Ryder Scott Co
	101.a(i)			XBRL Document