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~~Eni's business activities: ~~Exploration~~“Exploration & ~~Production,~~Production” (or “E&P”), “Gas & Power” (or “G&P”), “Global Gas & ~~Power, Refining~~LNG Portfolio” (or “GGP”), “Refining & Marketing and ~~Chemicals, Corporate~~Chemicals” (or “R&M & C”), “Eni gas e luce, Power & Renewables” and “Corporate and Other ~~activities.~~

~~References~~activities”.References to Versalis or Chemical are to ~~Eni’s~~Eni's chemical activities which are managed through its fully-owned subsidiary Versalis and ~~Versalis’~~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 ~~asses~~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 ~~the~~opposed to first generation ~~feedstock~~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~~ (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 ~~also~~ 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~~)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.~~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 ~~100% Scope~~GHG emissions (Scope 1 and Scope 2 ~~GHG emissions~~in tonnes CO2 eq.) of ~~Eni’s~~the main industrial activities ~~(on an operatorship basis) and produced energy, converted for~~operated by Eni divided by the productions (converted by homogeneity into barrels of oil ~~equivalent.~~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 (CO22eq~~eq)~~) 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.

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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 and consumed in assets that are owned or controlled by the company.~~parties.
	Scope 3 GHG Emissions			Indirect GHG emissions associated with the value chain of Eni’s products.
	SERM (Standard Eni ~~products along their full value chain.~~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.

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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 ~~segment~~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	= ~~5,408~~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 ~~0.00647~~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	~~= 1.016 tonnes~~ ~~= 1 metric ton~~ = 1 metric ton of crude oil	~~= 2,240 pounds~~ ~~= 1,000 kilograms~~ ~~= approximately 2,205 pounds~~ = approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees)

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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 ~~performance. Because it is a commodity business, the~~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 ~~a number of~~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. ~~Worldwide~~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. ~~Other factors which~~Factors that can influence the global economic activity in the short-term and demand for crude oil ~~are~~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, ~~and~~ improving living standards ~~prices~~ 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 ~~fight global warming,~~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 ~~and supplies of~~for crude oil over the long-term and may lead to structural lower crude oil demands and ~~consumption; see~~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. ~~Furthermore,~~

Global production of crude oil ~~demand~~ is ~~subject~~controlled to several, unpredictable events. Geopolitical tensions, local conflicts, terrorism, attacks, social instability, widespread civil unrest, pandemic diseases could dent consumers’ confidence, economic growth and hence global demand for oil.

~~Historically,~~a large degree by the OPEC cartel, ~~and lately the OPEC+ agreement,~~ which ~~includes OPEC members and~~has recently extended to include other important oil producers like Russia ~~have exerted a big influence over global supplies of crude oil~~ and ~~crude oil prices.~~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 ~~USA~~United States and the EU against certain producing countries may influence trends in crude oil prices. However, we believe that the ~~resurgence~~continued rise of crude oil production in the ~~USA~~United States due to the technology-driven shale oil revolution has somewhat reduced the ability of ~~OPEC~~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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The price of crude oil has been on a downtrend for the last six years, shedding more than two thirds of its value in this timeframe (from approximately 110 $/BBL in 2014 to the current level below 30 $/BBL as of end of March 2020). The development has been mainly driven by a supply glut fuelled by continued grow in the production of tight oil in the USA and the need of US independent producers to recover their investments, at a time when the pace of increase in crude oil demand has moderated. These trends have been exacerbated by the adverse developments recorded in the first quarter 2020 (see below). At the beginning of 2019, crude oil prices rebounded somewhat from another stage of the down cycle recorded in the final part of 2018, when the price of the Brent crude oil benchmark fell to around 50 $/barrel (Source: Platt’s Oilgram), supported by the production cuts implemented by the OPEC+ agreement and by production losses for Venezuela and Iran due to geopolitical factors. Brent prices peaked at 75 $/barrel in April 2019. Then, a new downward trend commenced pushing crude oil price down to the mid-$50 range during the summer months of 2019. The correction was driven by a global economic slowdown impacting fuel demand, uncertainties relating to the developments of the United States-China trade dispute and Brexit, and building oversupplies due to rising production levels in the United States and elsewhere. Against this backdrop, the September 2019 air attacks against strategic oil facilities in Saudi Arabia, which were of unprecedented reach and scale and caused a massive albeit temporary production loss, had little effects on crude oil prices because due to large worldwide supplies, no significant disruptions occurred in the marketplace and after a brief spike, crude oil prices reverted to then ongoing downtrend.

In the last part of 2019 and the beginning of 2020, crude oil prices tried to rebound, supported by the renewal of the OPEC+ agreement through the end of March 2020, which provided an increase of 500 KBBL/d in the production cuts to the target of 1.7 million BBL/d, with Saudi Arabia committing itself to cut its production quota by a further 400 KBBL/d. Other factors supportive of crude oil prices were the resurgence of geopolitical tensions in the Gulf area, a de-escalation in the trade dispute between the USA and China and early signs of a strengthening global economy. As a result of these trends, in 2019 the price for the Brent crude oil benchmark averaged 64 $/barrel, 9% lower than in 2018.

After a solid start in 2020 with Brent prices rising up to 65 $/barrel, crude oil prices took a hit due to a sudden drop in demand triggered by the outbreak of a pandemic disease known as COVID-19 spreading from China to other countries around the world. The sell-off intensified through February and early March 2020 as governments across the globe stepped up efforts to contain the virus, impacting economic activity and travel. In early March 2020, members of the OPEC+ agreement failed to reach a deal for additional production cuts claimed by some members to counteract the effects of the COVID-19 ~~effects. These developments~~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. ~~The~~At the peak of the COVID-19 crisis and the price war, the value of the Brent crude benchmark ~~has~~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 ~~more 50%~~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 ~~value recorded before the onset~~members of the disease at more than 65 $/bbl in early January 2020. Depending on how the current COVID-19 crisis unfolds, on how long it takes to contain the virus and on the severity of an ensuing economic downturn,OPEC+ as well as ~~on future developments regarding~~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 ~~willingness~~end of the ~~OPEC+ agreement~~summer and in the autumn months due to ~~support~~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 ~~ongoing~~final months of 2020 and in the first months of 2021 due to a favourable combination of market and macro developments, ~~could materially~~most notably: a break-through in the development and ~~negatively affect~~approval of effective vaccines against COVID-19, further acceleration in the ~~outlook for~~pace of economic activity in Asia, the ~~Company, its results~~outcome of ~~operations, cash flow and business prospects including shareholders' returns and~~ the ~~price of Eni's share. More information is disclosed~~presidential election in ~~Item 5 – Management~~the United States which fuelled expectations of ~~operations.~~

~~Management expects~~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 ~~growth~~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 ~~subdued~~volatile and uncertain in ~~2020 and possibly to decline~~2021 due to the ~~effects~~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 ~~economic activity~~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 ~~travel. For the medium term, management expects global oil~~in January 2021 natural gas prices staged a material comeback supported by record seasonal demand to resume growing at a rate in line with historical averages. Global crude oil supplies are expected to grow at a moderate pace. International oil companies are expected to retain a selective approach to investment decisions due to cash flow considerations and also the growth rate in the ~~production of tight oil in the USA is expected to slow down due to greater focus on capital discipline~~Northern-Eastern hemisphere driven by ~~US independent upstreamers. The cohesion of OPEC+ alliance is a factor of uncertainty to the global balance between supplies and demand.~~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 ~~oil~~ 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. ~~Based on~~In 2020, the ~~current portfolio~~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 ~~assets, Eni’s management estimates that~~prices, lower refining margins and other declines as described below) reduced the Company’s ~~consolidated~~underlying operating profit and the net cash provided by operating activities ~~would~~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 ~~€0.15 billion~~€150 million for each one-dollar change in the price of the Brent crude oil benchmark ~~with respect~~compared to the ~~price case assumed~~50 $/bbl scenario adopted by management for the current year and for proportional changes in ~~Eni’s financial projections for 2020.~~

~~The price of natural~~ gas generally follows a trend similar to that of crude oil, but it can also exhibit greater movements either upward or downward. In 2019, due to a combination of factors including lower gas demand in Asia due to the downturn and a recovery in Japan’s nuclear power production, larger globalprices.

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~~supplies~~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 ~~LNG, mild global temperatures~~the oil and ~~increased US production,~~natural gas prices at the main worldwide markets fell by a far bigger amount than crude oil prices. For example, the price of gas at the Italian spot market against which the realized price of our equity gas production in Europe is benchmarked, declined by 34% compared to 9% for the price of crude oil.

In 2019, the Company estimated that lower hydrocarbon prices negatively affected the Exploration & Production operating profit for approximately €2.23 billion, with the large majority of this loss deriving from lower gas prices.

markets. Lower oil and gas prices over prolonged periods of time ~~or, in the worst of the scenarios, a structural decline in oil and gas prices~~ may have material adverse effects on Eni’s performance and business outlook, because such a scenario may limit the Group’s ~~funds available~~ability to finance expansion projects, further reducing the Company’s ability to grow future production and revenues, and to ~~discharge~~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 ~~also could result~~ in the de-booking of proved reserves, if they become uneconomic in this type of environment. ~~Finally,~~

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 ~~weakened~~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 ~~industry conditions and resulting revisions made~~at the Italian spot market “PSV” is estimated at 5.5 $/mmBTU in real terms in 2023 as compared to ~~rating agency commodity~~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 ~~assumptions, lower commodity prices may also reduce~~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. All of 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.

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 ~~characterised~~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. ~~If oil prices differ significantly from~~

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 ~~own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.~~share.

Margins on the ~~production~~manufacturing and sale of fuels and other refined products, chemical commodities, and other energy commodities ~~and in the wholesale marketing of natural gas~~ are driven by economic growth, global and regional dynamics in supplies and ~~demands~~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

~~Eni faces strong competition in each of its business segments.~~

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, both~~opportunities. The economic crisis caused by the suppression of industrial activity and travel in ~~Europe~~response to the COVID-19 pandemic materially and ~~worldwide.~~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

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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

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wholesale ~~gas~~ markets to sell gas to industrial customers, the thermoelectric sector and ~~retailer~~retail companies from other gas wholesalers, upstream companies, traders and other ~~players both~~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 the Italian market and in markets across Europe. In recent years, competition has been fuelled by muted demand growth, oversupplies and the development of very liquid European spot markets where largesharply lower gas consumption leading to intensified competitive pressures. These developments caused lower sales volumes of gas ~~are traded daily. Players are competing mainly in terms of pricing~~marketed via pipeline and ~~to a lesser extent, on the ability to offer additional services~~by our LNG business and significantly lower prices. In 2020 Eni’s gas and LNG sales declined by 11% due to the ~~buyers~~impact of the ~~commodity, like volume flexibilities, different pricing options,~~economic crisis triggered by the ~~possibility~~pandemic. Sales margins at our LNG business were put under pressure by collapsing demand due to ~~change~~ the ~~delivery point and other optionality. Eni’s Gas & Power segment also engages~~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 ~~supply~~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 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 located in urban areas. The retail market is characterised by strong competition among local selling companies which mainly compete in term of pricing and the ability to bundle valuable services to 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 option on part of residential customers to switch smoothly from one supplier to another. Management believes that competition in the European wholesale and retail gas markets will continue to negatively affect the performance of Eni’s GasLNG.

Refining & ~~Power segment in future reporting periods.~~Marketing

•

Eni is facing strong competitive pressure in its business of gas-fired electricity generation which is largely sold in wholesale markets in Italy. Margins on the sale of electricity have declined in recent years due to oversupplies, weak economic growth and inter-fuel competition. Management believes that these factors will continue to negatively affect crack-spread margins on electricity at Italian wholesale markets and the profitability of this business unit in the foreseeable future.

•

In the Refining & Marketing segment, Eni is facing competition both in the refining business and in the retail marketing activity. Our Refining business ~~in recent years~~ has been negatively affected for years by ~~a number of~~ 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, ~~also~~ 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 ~~a situation of~~ global oversupplies of refinery products. ~~Furthermore, Eni’s refining margins are exposed~~Due to ~~the volatility~~a reduced profitability outlook 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 complex refineries are able to process sour crudes which typically trade at a discount over the Brent crude. Historically, this discount has supported the profitability of complex refineries, like our plant at Sannazzaro in Italy. However, in the course of 2019, a shortfall in supplies of sour crudes due to the production cuts implemented by OPEC, lower exports from Venezuela and the United States’ sanctions against Iran, drove an appreciation of the relative prices of sour crudes as compared to the Brent, which negatively affected the results of our refining business, ~~by reducing~~management recognized impairment charges of €1.2 billion to align the ~~advantage~~book value of processing sour crudes. This development triggered a revision of the profitability outlook of our complex plants, resulting in the recording of an impairment loss of approximately €684 million at our high-conversion Sannazzaro refinery. Ourrefineries to their realizable values.

The business of marketing refined products to drivers at our network of service stations ~~network~~ and to large ~~accounts customer (aviation airlines,~~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 ~~quality.~~

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~~In the Chemical business, Eni is facing strong competition from well-established international~~

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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

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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), ~~whose~~where demand is a function of macroeconomic growth. Many of these competitors based in the Far East and the Middle East ~~are~~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 ~~the~~ climate change and the preservation of the environment has begun to negatively affect the consumption of single-use plastics. In ~~2019,~~2020, these competitive dynamics were greatly amplified by the ~~operating performance~~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 ~~Eni’s Chemical business was negative due lower demand from end-user markets, particularly~~case of sales volumes of elastomers to the automotive ~~market, reflecting a global economic slowdown and lower demand~~industry. However, other chemicals segments performed relatively well, because the “stay-at-home economy” boosted demands for single-use plastics driven by stricter regulations and rising environmental sensitivity. The effects of those trends were exacerbated by the above mentioned competitive dynamics, resulting in a continued pressure on petrochemicalcertain products ~~margins. The Company does not expect any meaningful improvement~~like polyethylene, that is utilized in the ~~trading~~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 ~~short~~Chemicals businesses will remain challenging due to uncertainties and risks relating to the ~~medium-term~~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

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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 ~~competitive headwinds described above~~the progressive liberalisation of the market and ~~expectations~~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 ~~moderate~~the year. We anticipate that competition will remain strong in this business due to the likelihood of a slow economic ~~growth.~~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, ~~deriving from~~which may increase in case of a weaker-than-anticipated recovery in the ~~competition~~post-pandemic economy or in ~~its business segments, they may adversely impact~~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, ~~and~~ shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s ~~share.~~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 ~~life cycle~~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 ~~both~~ on several factors and variables , including the hazardous nature of the products transported due to their flammability and ontoxicity, the transportation methods ~~used (mainly pipelines,~~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 arisks of blowout, fire and loss of containment ~~of hydrocarbons and other hazardous materials,~~ and, given ~~the~~that normally high volumes are involved, could present a significant ~~risk~~risks to people, the environment and the property.

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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 ~~with~~by applying the best available ~~techniques.~~techniques in the marketplace. However, these measures may ultimately not ~~ultimately~~ be completely successful in ~~protecting against those risks.~~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 ~~unforeseen incidents, including releases or~~ oil spills, blowouts, fire, ~~mechanical failures~~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 ~~or destruction~~ to properties, environmental ~~damage,~~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 ~~share.~~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 ~~sufficient~~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 ~~the event~~case of ~~such~~ 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 ~~share~~shares and could also damage the Group’s reputation.

~~Rising public concern related~~Risks deriving from Eni’s exposure to ~~climate change has led~~weather conditions

Significant changes in weather conditions in Italy and ~~could continue~~in the rest of Europe from year to ~~lead to the adoption of national and international laws and regulations which are expected to result in a decrease of~~year may affect demand for ~~hydrocarbons~~natural gas and ~~increased compliance costs~~some refined products. In colder years, demand for such products is higher. Accordingly, the ~~Company. Eni is also exposed to risks~~results of ~~technological breakthrough~~operations of our businesses engaged in the ~~energy field~~marketing of natural gas and, ~~risks of unpredictable extreme meteorological events linked~~ to a lesser extent, the ~~climate change.~~

~~Growing worldwide public concern over greenhouse gas (GHG) emissions and climate change,~~Refining & Marketing business, as well as ~~increasingly stricter regulations~~the comparability of results over different periods may be affected by such changes in weather conditions. Over recent years, this ~~area,~~pattern could ~~adversely affect~~have been possibly affected by the ~~Group’s business. Those risks may~~

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The production of oil and natural gas is ~~a capital-intensive business with significant up-front cash-outs~~highly regulated and ~~extended pay-back periods of investments. Finally, it~~ is ~~strictly regulated and~~ subject to conditions imposed by governments throughout the ~~world.~~

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.

~~Exploring for finding hydrocarbons reserves~~Exploratory drilling efforts may be unsuccessful

Exploration ~~drilling for oil and gas involves numerous risks including~~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.~~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~~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 ~~or others~~ 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 ~~for~~and granting of all necessary administrative authorizations to build pipelines and related equipment to transport and market hydrocarbons;

•

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 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 ~~are typically~~normally have long lead ~~time~~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 ~~agreement~~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

~~Unless~~In case the ~~Company is able to replace~~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~~”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 ~~530~~330 barrels/d for each $1 change in oil prices based on current Eni’s assumptions for oil prices. In ~~2019,~~2020, production and year-end proved reserves benefitted ~~marginally of~~from lower oil prices which translated into higher ~~entitlements.~~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~~above-mentioned sensitivity of production to oil price changes may be significantly different.

Future oil and gas production is ~~dependent on~~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 ~~entities~~ 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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~~projections~~management’s assumptions regarding future rates of production and costs and timing of operating and development ~~expenditures;~~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 ~~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~~underlying the estimation of proved reserves involve management’s judgement or are ~~subject to~~outside management’s control (prices, governmental regulations) and may change over time, ~~and~~ therefore ~~affect~~affecting the estimates of oil and natural gas ~~reserves.~~reserves from year-to-year.

The prices used in calculating Eni’s estimated proved reserves are, in accordance with the ~~U.S. Securities and Exchange Commission (the “U.S.~~ SEC”) requirements, calculated by determining the unweighted arithmetic average of the ~~first-day-of-the-month~~first day-of-the-month commodity prices for the preceding 12twelve months. For the 12-months ending at December 31, ~~2019,~~2020, average prices were based on 6341 $/~~barrel~~BBL for the Brent crude ~~oil; it~~oil, which was 71materially lower than the reference price of 63 $/~~barrel~~BBL utilized in ~~2018.~~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 ~~2018.~~2019. Those reductions resulted in usEni having to remove ~~volumes~~124 MBOE of proved reserves because they have become uneconomical ~~at the prices of 2019. Furthermore, compared to the 2019 reference~~in this price Brent prices have declined materially in the first quarter of 2020. If such prices do not increase significantly in the coming months, Eni’s future calculations of estimated proved reserves will be based on lower commodity prices which would likely result in the Company having to remove non-economic reserves from its proved reserves in future periods.environment.

Accordingly, the estimated reserves reported as of the end of ~~2019~~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.~~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, ~~2019,~~2020, approximately ~~29%~~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.~~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, ~~2019~~2020 includes estimates of total future development and decommissioning costs associated with the Group’s proved total reserves of approximately ~~€35.7~~€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%. ~~In 2019 the effective tax rate was 97.3% due to a particularly unfavourable oil and gas price scenario.~~

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.

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exploration ~~leases.~~leases, is in effect. Following the plan approval, exploration permits will resume ~~their efficacy~~ in areas that have been identified as suitable and new exploration permits can be ~~awarded; on the contrary,~~awarded. However, in unsuitable areas, exploration permits ~~are~~will be repealed, applications for obtaining new exploration permits ongoing at the time of the law enactment ~~are~~will be rejected and no new permit ~~application~~applications can be filed. As far as development and production concessions are concerned, pending the national plan approval, ongoing concessions ~~retain their efficacy~~remain in effect and administrative procedures underway to grant ~~extension~~extensions to expired ~~concession~~concessions remain unaffected; ~~instead~~however, no applications to obtain new ~~concession~~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; ~~on the contrary~~however, development and production concessions ~~current~~in place as at the approval of the national plan that fall in unsuitable areas ~~are~~will be repealed

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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

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Venezuela is currently experiencing a situation of financial stress, ~~amidst an~~which has been exacerbated by the economic ~~downturn due to lack~~recession caused by the effects of the COVID-19 pandemic. Lack of financial resources to support the development of the country’s hydrocarbons reserves ~~which have~~has negatively affected the ~~Country~~country’s production levels and hence ~~petroleum~~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 ~~the United States’ market,~~U.S. markets, which is the main outlet of Venezuelan production (see also “− ~~Sanctions targets~~”“Sanctions targets” below).

~~Due to a deteriorated operating environment,~~Presently, the ~~Group was forced to de-book its proved undeveloped reserves at its two major petroleum projects~~Company retains only one valuable asset in ~~the Country in recent years:~~Venezuela: the 50%-participated Cardón IV joint venture, which is ~~currently~~ operating a natural gas offshore project and is supplying ~~the product~~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 ~~PetroJunín oilfield project~~Corocoro field, with respect to which in ~~joint venture~~past years we have registered significant impairment losses and reserves de-bookings, with ~~PDVSA. This latter project was almost entirely written off in 2018. Also the Group has incurred credit losses due~~currently little value left to recover. The main risk to Eni’s ability to recover its investment is the continued ~~difficulties~~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 ~~accounting~~booking a loss provision on the revenues accrued. The expected credit ~~expected~~ 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 ~~has been~~was estimated. In the course of 2019 the situation has stabilized, since the Group was able to collect a percentage of gas receipts which was in line with management’s estimates made in 2018 of the expected credit losses and no further credit allowances were recorded. As of December 31, ~~2019,~~2020, Eni’s invested capital in Venezuela was approximately ~~$1.3~~$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 ~~Venezuela~~the country to remain a risk factor to ~~its~~Eni’s operations ~~in the Country~~there for the foreseeable future.

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Starting from 2017, the United States ~~administration~~ enacted ~~certain financing~~a regime of economic and financial sanctions against ~~Venezuela, which prohibit any United States person to be involved in all transactions related to, provision~~Venezuela. The scope of ~~financing for, and other dealings in, among other things, any debt owed to~~ the Government of Venezuela that is pledged as collateral after the effective date, including accounts receivable. Recently, the United States administration has resolved to impose an embargo on the import of crude oil from Venezuela state-owned oil company, PDVSA and has restricted the ability of United States dealers to trade bondsrestrictions, initially targeting certain financial instruments issued or sold by the Government of Venezuela, was gradually expanded over 2017 and ~~its affiliates. Further increases of the prohibitions against the Government of Venezuela (and the entities owned or controlled by it) has been enacted~~2018 and then significantly broadened during the course of 2019 ~~with inclusion of our Venezuelan partner, PDVSA, in~~when Petroleos de Venezuela SA (“PDVSA”), the main national state-owned enterprise, has been added to the “Specially Designated Nationals and Blocked Persons ~~List~~List” and ~~the introduction of measures intended to freeze the assets of~~ the Venezuelan governments and of its ~~affiliated persons.~~controlled entities became subject to assets freeze in the United States. Even if ~~the current US~~such U.S. sanctions are substantially “primary” and therefore ~~substantially~~ dedicated in principle to USU.S. persons only, retaliatory measures and other adverse consequences may also interest ~~also~~ foreign entities which operate with Venezuelan listed entities ~~as it may occur~~and/or in the ~~case~~oil sector of ~~transactions which show a US nexus, which may trigger~~ the ~~application~~country. The U.S. sanction regime against Venezuela has been further tightened in the final part of ~~sanctions.~~ 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 ~~sanction~~sanctions risk which may affect its business operation. In any case, the ~~US sanction are expected to~~U.S. sanctions add ~~further~~ 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.~~investments in Venezuela.

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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 ~~the~~ of plants and infrastructures, ~~and~~the health of employees, contractors and other ~~Company’s~~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 ~~resulting~~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 ~~in the environment~~ of soil, water or ~~ground water~~groundwater contaminants, emissions of toxic gases and other air pollutants or can impose taxes on polluting air emissions, ~~and noxious gases~~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 ~~willful~~wilful release of pollutants and contaminants into the atmosphere, the soil, water or groundwater or exceeding the ~~overcome of~~ concentration ~~threshold~~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 ~~willful~~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 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 ~~result~~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 ~~we have~~Eni has experienced in recent years a number of temporary plant shutdowns at our Val d’Agri ~~profit~~oil treatment centre due to environmental issues and oil ~~spill overs,~~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 ~~share.~~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 ~~a number of~~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, ~~nor~~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 ~~obligation exists~~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

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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.

~~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 the Gas & Power segment 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.

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 ~~share.~~shares.

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breach of the regulation. The GDPR requires mandatory breach notification, ~~the~~a standard ~~for which is~~ 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.

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

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.~~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.

~~Exposure~~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 ~~commodity risk has been described in~~volatility of refining margins and of certain portions of the ~~paragraph above.~~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 ~~formula~~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.

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We are exposed to credit risk; our counterparties could default, could be unable to pay the ~~liquidity~~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 ~~case~~its Exploration & Production business due to the ~~Group fails~~magnitude of the exposure at risk and to ~~access~~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~~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 ~~a number of~~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 ~~situation~~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 ~~certain hydrocarbons-exporting countries whose financial conditions have sharply deteriorated following~~new restrictive measures in response to a resurgence of the ~~protracted downturn~~pandemic leading to a double-dip in ~~crude oil prices. 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 ~~Eni’s~~ long-term investment ~~program~~programs. Low investments to develop our reserves may ~~be impacted with a consequent effect on~~significantly and negatively affect Eni’s business prospects, ~~and~~ results of operations and cash ~~flows.~~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 ~~2020,~~2021, Eni expects to make capital expenditures slightly below the level of ~~approximately €4~~€6 billion, of which about 70% in the Exploration & Production segment, at the planned exchange rate of ~~1.12~~1.19 USD/EUR. Historically, Eni’s capital expenditures have been financed with cash generated byfrom 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:

•

the amount of Eni’s proved reserves;

•

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

•

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

•

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

•

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

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, ~~prospects,~~financial condition, results of operations, and cash ~~flows.~~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 ~~growing~~ portion of Eni’s cash flows from operations to be used for the payment of interest and principal on its ~~debt.~~

~~We are exposed~~debt, thereby reducing its ability to ~~credit risk; our counterparties could fail or could be unable~~use cash flows to ~~pay the amounts owed to us~~fund capital expenditures and ~~to meet their performance obligations under contractual arrangements. In the last few years, the Group has experienced a level of counterparty default higher than in previous years due to~~dividends.

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Item 4. INFORMATION ON THE COMPANY

History and development of the Company

Eni SpA with its consolidated subsidiaries engages in the exploration, development and production of hydrocarbons, in the supply and marketing of gas, LNG and power, in the refining and marketing of petroleum products, in the production and marketing of basic petrochemicals, plastics and elastomers and in commodity trading. Eni has operations in 66 countries and 32,053 employees as of December 31, 2019.

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, 13th13th 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 ~~principal~~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 ~~operations~~Eni, substantially confirming the pre-existing setup, are ~~described below.~~identified as follows:

•

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 4142 countries, ~~including~~most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, ~~Australia,~~ Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and United Arab Emirates. In ~~2019,~~2020, Eni average daily production amounted to ~~1,736~~1,609 KBOE/d on an available- for-sale basis. As of December 31, ~~2019,~~2020, Eni’s total proved reserves amounted to ~~7,268~~6,905 mmBOE, which include subsidiary undertakings and proportionally consolidated entities and Eni’s share of reserves of equity-accounted joint ventures and ~~proportionally consolidated entities.~~associates.

~~Eni’s~~

•

Global Gas & ~~Power segment~~LNG Portfolio: engages in the ~~supply, trading~~wholesale activity of supplying and ~~marketing of~~ selling natural

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gas via pipeline and LNG, and ~~electricity,~~the international transport activity. It also comprises gas ~~transport~~trading activities targeting both hedging and ~~commodity trading~~stabilizing the Group’s commercial margins and ~~derivatives. This segment also includes~~optimizing the ~~activity of electricity generation that is ancillary to the marketing of electricity.~~gas asset portfolio. In ~~2019,~~2020, Eni’s worldwide sales of natural gas amounted to ~~73.07~~64.99 BCM, of which ~~37.85~~37.30 BCM was in Italy. ~~Eni produces power at a number of operated gas- fired plants in Italy with a total installed capacity of 4.7 GW as of December 31, 2019. In 2019, electricity sold totalled 39.49 TWh.~~ The LNG business includes the purchase and marketing of LNG worldwide, with a large ~~incidence~~proportion of equity LNG supplies. The Group serves the gas and power wholesale and retail markets in Italy and in a number of European markets. As at December 31, 2019 the Gas & Power segment had 9.4 million retail customers. The Gas & Power segment comprises results of the Group activities intended to manage commodity risk of asset-backed trading activities and proprietary trading. Furthermore, this activity includes the result of crude oil and products supply, trading and shipping.

~~Eni’s~~ •

Refining & Marketing and ~~Chemical segment includes~~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 ~~chemicals~~chemical business ~~which~~ 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 into the cargo market, to large business accounts (airlines companies, bunker, public administrations, operators of privately-held networks of service stations) and to retail ~~and wholesale markets mainly~~customers through a network of proprietary or leased service stations in Italy and in the rest of ~~Europe, as well as in the petrochemical business.~~Europe. Production of refined products derives from both oil-based refineries and from manufacturing processes based on renewable feedstock. As of December 31, ~~2019, balance~~2020, the balanced refining capacity was ~~732~~548 KBBL/~~d including our share of capacity at ADNOC Refining (UAE) where we acquired a 20% interest in 2019.~~d. In ~~2019,~~2020, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to ~~23.05~~17.71 mmtonnes (of which traditional refinery throughputs were ~~22.74~~17 mmtonnes and bio refinery throughputs were ~~0.31~~0.71 mmtonnes) and sales of refined products were ~~32.27~~26.08 mmtonnes, of which ~~25.56~~20.02 mmtonnes were in Italy. Retail sales of refined products at Eni’s service stations amounted to ~~8.25~~6.61 mmtonnes in Italy and in the rest of Europe. In ~~2019,~~2020, Eni’s retail market ~~shares~~share in Italy through its “Eni” branded network of service stations was ~~23.7%~~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 ~~2019,~~2020, production volumes of

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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 ~~Company over the next thirty years. This evolution~~business model and the underlying ~~actions~~action plan ~~aim at maximizing~~will be accomplished over a thirty-year timeframe and will significantly increase the ~~economic~~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 ~~fast changing~~rapidly-changing energy ~~market while delivering a deep reduction in GHG emissions from our operations and our products.~~

landscape. The ~~principles~~strategic guidelines that ~~are the basis of our business strategy and~~ will drive ~~the~~our evolution ~~of our portfolio~~going forward are:

•

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

•

toTo maximize the integration of the portfolio along the entire value ~~chain, from production to final sale of conventional, bio and renewable products;~~chain;

•

~~to focus on~~To retain a financial framework which prioritizes capital discipline ~~to maintain~~and a strong balance sheet;

•

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;

•

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

•

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 ~~sustain~~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.

•

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.

•

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;

•

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.

•

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 ~~generation; and~~driven by rising oil prices above the threshold of 43 $/bbl up to 65 $/bbl. See Item 5 – Management Expectations of Operations.

•

In 2020, in order to ~~maintain a progressive~~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 ~~remuneration~~return policy.

In•

Our oil&gas production plans have been revised to discount our ~~evolution path we design a more integrated~~changed cash allocation priorities and ~~sustainable Company, which will be able~~reduced expenditures to ~~compete effectively~~develop our reserves both in 2020 and in the ~~global energy market leveraging~~following years. In 2020, our oil&gas production on ~~its~~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 ~~asset base, technologies~~facilities and ~~competencies~~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 ~~the ongoing development~~an easing of the ~~new businesses of renewables and circular economy.~~production cuts enacted by OPEC.

~~On the basis~~

•

We are assuming a long-term crude oil price of the ~~four firm principles, operational strategies have been defined~~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 ~~2035~~our planning assumptions, investment decision processes and 2050, which outline the evolutionary and integrated path of all of our business units. The speed of evolution and the relative contribution of each business will depend on market trends, technological developments and legislation and the success of our implementationevaluation of the ~~strategy~~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 ~~each business. Our goals for each businesses are follows:~~

~~In the E&P business:~~

•

~~to strengthen~~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.

•

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.

•

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.

•

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.

•

In the gas&power retail marketing business, we plan to improve the profitability of our operations, which will be ~~characterized~~driven by an expected growth of our customer base, the offering of innovative products and services with a ~~low breakeven,~~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.

•

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 ~~fast time~~modest recovery in Brent crude oil prices that are projected to ~~market~~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 ~~limited exposure beyond~~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 ~~term;~~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:

•

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°

•

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:

•

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

•

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

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

•

progressive reduction of the hydrocarbons production atin the medium long term, with an ~~average rate~~increasing share of ~~3.5% till 2025. After this year, we expect production to start a flexible decreasing trend mainly~~gas in ~~its oil part.~~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 ~~the vast majority~~a large part of the value of our reserves by 2035 ~~assuming a flat Brent price~~under the most conservative scenario assumptions;

•

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

•

increase the focus on equity gas in Global Gas & LNG Portfolio, progressively reducing the marketing of ~~$50/bbl. The~~ gas ~~share of~~purchased from third parties;

•

expand production ~~is expected~~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);

•

evolve the product mix marketed to our retail customers, with the aim to reach ~~60%~~100% of de-carbonized products by ~~2030 and around 85% in~~ 2050;

•

expand the business of circular economy, which comprises several business initiatives designed to ~~invest significantly in exploration activities with a view~~make the best use of ~~increasing the geographical diversification~~industrial and ~~optionality of the portfolio;~~civil waste, both organic and inorganic, through re-use or recycling aiming at producing energy feedstock and reusable finished products;

•

~~to grow the cash generation.~~

~~In the renewables business:~~

•

~~to grow our presence in~~scale up the business of power generation from renewable sources, targeting a progressive expansion of the installed global capacity with the aim to ~~over 55GW~~reach 60 GW by ~~2050, with an intermediate target of 5GW by 2025; and~~2050;

•

increase the production of green and blue hydrogen coupled with projects to ~~expand to new areas based on where we have an existing or targeted customer base in order to maximize value from an integrated model.~~capture and store CO2;

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~~Therefore,~~•

ramp up the participation in ~~setting our targets of carbon reduction, we have included all emissions:~~

•

~~scope 1, 2 and 3;~~

•

~~from all the hydrocarbons produced or bought from third parties, in all businesses inside Eni’s energy portfolio; and~~

•

~~measured both on an absolute basis and in terms of intensity per unit of energy product sold.~~

~~We believe the implementation of our strategy and of our actions plans over the next thirty years to drive:~~

•

~~an absolute reduction in net lifecycle GHG emissions (scope 1, 2 and 3) by around 30% in 2035 and 80% by 2050 vs 2018; the target at 2050 exceeds the levels of reduction envisaged by IEA~~projects for ~~energy-related CO~~2 ~~in its SDS scenario that is commonly considered the main benchmark for the achievement of the goals of the Paris Agreement;~~

•

~~a reduction of 55% by 2050 vs 2018 in net carbon intensity per unit of energy product sold; and~~

•

~~zero net carbon footprint (scope and 2 emissions) for the entire Eni Group by 2040.~~

~~Our carbon footprint reduction will be driven by:~~

•

~~increasing the weight of gas production on our overall hydrocarbons production, which is expected to decline beyond 2025 in its oil component;~~

•

~~increasing the focus on equity gas products in G&P, progressively reducing the marketing of gas purchased from third-parties;~~

•

executing projects designed to convert our existing European refineries into bio-refineries and to expand the business of circular economy, which comprises a number of business initiatives designed to make the best use of industrial and civil waste, both organic and inorganic, through the re-use or the recycling aiming at producing energy feedstock and reusable finished products; and

•

~~implementing projects of carbon capture and storage (CCS) and of~~ forest conservation and preservation with the goal of ~~capturing~~obtaining allowances to offset up to 40 ~~Mtons per year~~MTPA of CO2., in 2050, with an intermediate target more than 6 MTPA in 2024 and 20 MTPA in 2030.

~~In 2019 we reduced~~One of the milestones of our decarbonization strategy is to achieve by 2030 a net zero carbon ~~intensity~~footprint in our E&P business ~~to 19.58 tonnes of CO~~2 ~~equivalent per thousand of BOE, down by 9% from 2018 and by 27% from 2014 levels. This measure relates to gross operated production. We are targeting to achieve by 2030 net zero carbon footprint~~ relating to ~~Scope~~scope 1 and 2 emissions on equity basis, with an intermediate target of 50% reduction in ~~our upstream business (on equity basis) by:~~2024 vs. 2018. We are planning to reach this goal:

–

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

–

by offsetting residual upstream emissions through ~~large forestry projects.~~

~~Furthermore, we expect net~~the ramp up of our projects designed to build carbon ~~intensity to drop by around 15% by 2035 and 55% by 2050, benefitting also from~~sinks like the expansion of renewables capacity and carbon free products sold to our customer base, in particular with our retail base growing from 9 to an expected 20 million customers. This will make Eni’s overall energy offering highly sustainable.

~~In addition, our strategy would allow us to achieve scope 1 and 2 net zero carbon footprint~~projects for the ~~Eni Group by 2040.~~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 ~~49%~~48% of Eni’s production in ~~2019~~2020 on an available-for-sale basis; as of December 31, ~~2019,~~2020, gas reserves represented approximately ~~50%~~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 ~~$ per barrel.~~$/bbl. We believe that those ~~elements~~characteristics of our portfolio coupled with a relatively low pay-back period will mitigate the risk of stranded reserves going forward, ~~due to~~should risks of ~~lower~~structurally declining hydrocarbons ~~demand in response to~~demands materialize because of stricter global environmental constraints and regulations and ~~increasing public sensitivity to~~changing consumers’ preferences resulting in trends like the ~~issue~~mass adoption of ~~global warming.~~ 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 ~~when evaluating all such projects.~~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

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The IEA SDS forecasts demand for oil to peak before 2025 and then to decline to 50 million barrels/d by 2050 (currently it runs at approximately 100 million barrels/d). Gas demand is projected to remain stable around the current level of 4,000 billion cubic meters per year till 2040. The hydrocarbonshydrocarbon pricing assumptions of the IEA SDS scenario are ~~slightly lower than Eni’s pricing assumptions regarding crude oil (for example~~substantially aligned to the ones adopted by Eni in ~~2040 the price of crude oil is projected to be 10% lower~~its base case impairment review made in ~~the IEA SDS scenario compared to Eni’s own assumptions), while gas prices in the IEA SDS scenario are projected to be slightly higher than Eni’s scenario.~~accordance with IAS 36. CO2 emissions costs under the IEA SDS ~~assumptions will~~ show a strong uptrend consistent with the goal of encouraging the adoption of low carbon technologies. ~~Such~~The IEA SDS projects CO2 emissions costs ~~as estimated by the IEA SDS would~~in advanced economies to reach ~~up to~~ 140 $ per ton in real terms ~~2018 (referred to Advanced Economies),~~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 ~~indicated~~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, ~~in terms of carrying amounts and fair value,~~ determining a reduction of 7%11% in the total ~~fair value~~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 ~~2019~~2020 financial ~~statements.~~statements using the management’s base case scenario. That reduction falls to a 2%5% decline assuming the recoverability of CO2 costs in the cost oil or the deductibility from the taxable income.

~~Furthermore,~~Finally, management assessed the recoverability of the expected costs associated with the Company’s plans to ramp up the participation in projects for forestry conservation and protection from degradation, which is one of the tools of the Company’s path to decarbonization. Those projects which have been started in 2019 envisage the purchase of carbon credits certified in accordance to generally accepted international standards. Management projects to build in future years a portfolio of forestry projects intended to allow the Company to offset the net residual “Scope 1 and 2” carbon emissions of the E&P business calculated on equity production for the achievement of the carbon neutrality of the business from 2030 onwards. Those costs are considered part of the operating expenses of the E&P business and their recoverability has been evaluated in relation to the CGU E&P segment as a whole. When including those costs extrapolated along the reserves residual life in the determination of the value-in-use of the E&P segment, a 2% reduction in the headroom (excess of fair value over carrying amounts) of the entire business segment is observed compared to the result of the impairment review performed by the Company in the preparation of its 2019 financial statements.

Ultimately, under management’s assumptions for a long-term Brent price at 70 $/bbl (real terms 2022), which has remained unchanged for the last few years, and at a reference price for the Italian spot gas benchmark of 7.8 $/mmBTU, Eni’s oil&gas properties have exhibited a substantial resilience of their carrying amounts, as highlighted by the trend in the recognition of impairment losses in the last three years. In 2017 we recorded a net reversal of €158 million and in 2018 we recorded net impairment losses of €726 million; in 2019 we booked charges of €1.2 billion. Impairment losses in those three years have been driven mainly by asset-specific issues, which were acquired during a historic phase of suspected peak supply, and in relation to certain complex operating environments. However, considered the following trends ofin 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

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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.

•

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.

•

March 2021 – Finalized a series of agreements with the Arab Republic of Egypt (ARE)~~, the Egyptian General Petroleum Corporation (EGPC), the Egyptian Natural Gas Holding Company (EGAS)~~ and the Spanish ~~company~~partner Naturgy ~~which comprise plans~~ for ~~restarting~~the restart of the Damietta liquefaction plant ~~in Egypt by June 2020,~~and the resolution of all pending issues of the JV Uniòn Fenosa Gas with the Egyptian partners and the subsequent restructuring of the ~~UFG joint-venture (Eni 50%~~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 ~~Naturgy 50%) and~~lifted its first LNG cargo since the ~~settlement of~~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 ~~litigations with~~disputes between the ~~Egyptian partners.~~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.

•

March ~~2020~~2021 – ~~Eni became~~Signed an ~~active member alongside BioCarbon Partners~~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 ~~governance~~disposal of the ~~REDD+ Luangwa Community Forests Project~~Bhit/Badhra (Eni’s interest 40%) and Kadanwari (Eni’s interest 18.42%) operated fields and the participating interest in ~~Zambia,~~the Latif (Eni’s interest 33.3%), Zamzama (Eni’s interest 17.75%) and Sawan (Eni’s interest 23.7%) fields.

•

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.

•

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

•

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.

•

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 ~~commitment to purchase~~ carbon ~~credits for the next 20 years, until 2038.~~capture and storage of 4 million tonnes per year.

•

February ~~2020~~2021 – ~~Third successful well~~Signed an agreement with ~~Agogo 3 in~~Be Charge, to increase the ~~Block 15/06 (Eni operator with a 36.84% interest) after the two wells~~national supply of ~~the Agogo discovery made in 2019 already in production in the Block 15/06, offshore Angola. Two more discoveries, Ndungu and Agidigbo were made in the same Block in 2019.~~charging infrastructures for electric mobility. The charging station will be powered by renewable energy to be supplied by Eni gas e luce.

•

~~February 2020 – Made an oil discovery in the Saasken Exploration Prospect in the operated Block 10 (Eni’s interest 65%), offshore Mexico.~~

•

~~February 2020 – Started a 31 MW photovoltaic plant at the Porto Torres industrial site in Sardinia.~~

•

January ~~2020 – Made a gas and condensate discovery with the Mahani-1 well in the concession Area B, in the Emirate of Sharjah (UAE).~~

•

~~January 2020~~2021 – Awarded the operatorship ~~with a 60%~~of the exploration license P2511 (Eni’s interest 100%) in the ~~Block 28, offshore Angola.~~North Sea in the United Kingdom.

•

January ~~2020~~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.

•

January 2021 – Awarded 1710 new exploration licenses to Vår Energi in Norway, with 75 operatorships.

•

December 2019 – Signed an agreement with Falck Renewables for the joint development of renewable energy projects in the United States to develop at least 1 GW of installed capacity by the end of 2023.

•

~~December 2019 – Signed a production sharing contract for the exploration of an onshore block in Albania (Eni’s interest 100%), ratified by the authorities in March 2020.~~

•

December 2019 – Vår Energi, the joint venture between Eni (70%) and HitecVision (30%), finalized the acquisition of ExxonMobil’s upstream assets in Norway, with annual production of 150 kboe/d, for a total consideration of $4.5 billion fully financed by the JV.

•

December 2019 – Closed the disposal of a 20% interest to Neptune in the East Sepinggan block, offshore East Kalimantan in Indonesia, which includes the Merakes field and the East Merakes discovery. Eni will retain a 65% interest and the operatorship.

•

~~December 2019 – Awarded a 50 MWp photovoltaic project in the southern Kazakhstan, as a result of an auction managed by the Kazakh Authorities.~~

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•

~~October 2019~~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.

•

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.

•

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.

•

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.

•

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.

•

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.

•

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.

•

December 2020 – Signed an agreement with ~~Italian public~~Enel aimed at the study and ~~private authorities, Cassa Depositi e Prestiti (CDP), Fincantieri~~development of green hydrogen projects, through facilities powered by renewable energy.

•

November 2020 – Versalis signed an agreement with AlphaBio Control, a research and ~~Terna to set up a joint venture~~development company engaged in the production of natural formulations for the ~~development~~protection of crops, aimed at the production of herbicides and ~~installation~~biocides for the disinfection of ~~power plants feed with wave-energy.~~plant-based and biodegradable surfaces, using the active ingredients produced from the chemistry from the renewable sources platform of Porto Torres.

•

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.

•

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.

•

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).

•

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.

•

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.

•

October ~~2019~~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.

•

September 2020 – Made a ~~new near-field oil~~gas discovery in the Abu ~~Rudeis Sidri development lease, in the Gulf of Suez. Following the drilling in July 2019 of the appraisal well in the Sidri South.~~

•

~~October 2019 – Started production at the Obiafu 41 gas and condensate discovery, which was made in August 2019, in the OML 61~~Madi West (Eni operator with a 75% interest) concession ~~in the Niger Delta, just 3 weeks after well completion.~~

•

~~October 2019 – Launched a new line products based on proprietary technology, made of recycled raw materials from separated domestic waste collected in Italy.~~

•

October 2019 – Completed the acquisition of two construction-ready solar photovoltaic projects in the Northern Territory of Australia, 12.5 MW each at Batchelor and Manton sites, scheduled for completion by the third quarter of 2020.

•

~~September 2019 – Signed a co-operation agreement with Mainstream Renewable Power, a wind and solar development company, to develop projects.~~

•

~~September 2019 – Awarded to ArmWind LLP, joint venture between Eni and General Electric, of a project for a 48 MW wind farm in the Northern Kazakhstan following a reverse auction.~~

•

~~September 2019 – Started production at the Baltim South West gas project~~ in the Great Nooros Area in ~~Egypt,~~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 ~~just nineteen months after~~ the ~~FID.~~area, indicates that the Great Nooros Area gas in place can be estimated in excess of 4 Tcf.

•

August ~~2019 – Awarded the West Ganal exploration block in the Kutei Basin, offshore Indonesia as a result of the second conventional oil and gas bidding round 2019 (Eni operator with a 40% interest).~~

•

~~August 2019 – Reached a peak production of 2.7 bcf/d at the Zohr gas field, five months ahead of target established in the Plan of Development (PoD).~~

•

July 2019 – Closed the acquisition of a 20% interest in ADNOC Refining in Abu Dhabi, for a consideration of $3.24 billion. The transaction is part of Eni’s strategy aimed at achieving better geographical diversification of the portfolio and at rebalancing along the hydrocarbons value chain, with an increase of 35% interest of its refining capacity.

•

~~July 2019~~2020 – Signed ~~an Exploration and Production Sharing Agreement for Block 77, onshore Oman.~~

•

~~July 2019 – Made a gas and condensates discovery in~~through the ~~exploration permit Ken Bau, Block 114 (Eni operator with a 50% interest), offshore Vietnam.~~

•

~~July 2019 – Signed an agreement to divest to Qatar Petroleum a 13.75% share in the exploration blocks L11A, L11B and L12, offshore Kenya.~~

•

July 2019 – Made several discoveries in Egypt: two oil discoveries in the Meleiha development permit, a gas discovery in the onshore El Qar’a exploration lease in the Nile Delta and a oil discovery in the Gulf of Suez were also made, while production was started at the South West Meleiha development area.

•

July 2019 – Signed an agreement with the Italian farmers association for the enhancement of agricultural biomass to be used in the production of advanced biofuels, researching and promoting crops that can be used as alternative sources for green refineries and development of sustainable agriculture.

•

~~July 2019 – Granted rights for exploration and production of hydrocarbons at the Abay project, offshore Kazakhstan in joint venture with local State owned partners.~~

•

~~July 2019 – Awarded the operatorship of the Block WB03~~subsidiary Novis Renewables Holdings (Eni’s interest ~~70%~~49%), ~~offshore Ghana. The contract award is subject to approval from the Authorities.~~

•

~~July 2019 – Started early production at Area 1 offshore Mexico, in just eleven months after the final investment decision.~~

•

~~July 2019 – Signed~~ an agreement with the Tunisian Government for transporting Algerian natural gas through Tunisia. With this agreement, Eni undertakes to operate the pipeline for the next 10 years, through its subsidiary Trans Tunisian Pipeline Company (TTPC), committing to funding investments for infrastructure upgrading, while trying to benefit from the exclusive rights to the entire transport capacity.

•

June 2019 – Signed an agreement with the Italian Company, NextChem, MaireTecnimont’s green chemistry subsidiary, to develop and implement at Eni’s industrial sites in Italy, a conversion technology transforming non-recyclable waste into hydrogen and methanol.

•

~~June 2019 – Signed an agreement with Sonangol to establish a joint venture to assess and develop renewable energy opportunities in Angola.~~

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•

~~June 2019 – Signed contracts for two new exploration blocks, offshore Ivory Coast (Eni operator~~agreement with ~~a 90%).~~

•

~~May 2019 – Acquired a 10% stake~~Building Energy SpA to acquire Building Energy Holdings US (BEHUS) managing 62 MW of wind and solar capacity fully in ~~three blocks, A5-B, Z5-C and Z5-D in Mozambique, located~~operation in the ~~deep waters~~U.S.A. and a pipeline of ~~Angoche and Zambesi Basins.~~wind projects of up to 160 MW. Production from already in operation BEHUS assets is expected to avoid over 93 ktons of CO2/y.

•

~~May 2019~~August 2020 – ~~Awarded the MLO 124 exploration block, offshore Argentina.~~

•

~~May 2019 – Signed~~Versalis signed an agreement with ~~Sonatrach to renew the gas supply contract to import Algerian gas into Italy until 2027.~~

•

May 2019 – Approved by the government of Mozambique the development plan of the Rovuma LNG project, which will produce, liquefy and market natural gas from three reservoirs of the Mamba complex in the Area 4 block in the Rovuma basin. Plan details proposed design and construction of two liquefied natural gas trains, which will together produce more than 15 million tons of LNG per year.

•

~~May 2019 – Signed with Montello~~Forever S.p.A., a leading Italian company ~~focused on post-consumer plastic~~in the recovery and recycling ~~technologies, an agreement~~of post-consumer plastic to develop and market a new range of ~~plastic~~solid polystyrene products made from recycled packaging.

•

~~May~~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.

•

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.

•

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.

•

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.

•

July 2020 – Made a gas ~~and condensate~~ discovery in ~~CTP-Block 4 (Eni operator with a 42.47% interest)~~the license of North El Hammad, in the ~~Akoma exploration~~Bashrush prospect ~~offshore Ghana.~~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.

•

~~May 2019~~July 2020 – ~~Signed~~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.

•

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

•

June 2020 – Versalis signed an agreement with COREPLA (National Consortium for the Collection, Recycling and ~~Production Sharing Agreement (EPSA)~~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.

•

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.

•

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.

•

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 ~~National Oil and Gas Authority~~oil development, will lead to an overall production of ~~the Kingdom~~65,000 barrels of ~~Bahrain (NOGA) for Block 1, offshore Bahrain.~~oil equivalent per day (boed) by 2020.

•

~~April 2019~~March 2020 – ~~Finalized the acquisition of an offshore exploration concession~~Started up a wind farm in ~~the Emirate of Ras al Khaimah, awarded the operatorship~~Kazakhstan with a ~~90% share in the Area A.~~capacity of 48 MW.

For significant business and portfolio developments occurred from January ~~2019~~2020 to the beginning of March ~~2019~~2020 see also the Annual Report on Form 20-F ~~2018~~2019 filed to SEC on April ~~5, 2019.~~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 41forty-two countries, ~~including~~most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, ~~Australia,~~ Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and the United Arab Emirates. In ~~2019,~~2020, Eni average daily production amounted to ~~1,736~~1,609 KBOE/d on an available-for-sale basis. As of December 31, ~~2019,~~2020, Eni’s total proved reserves amounted to ~~7,268~~6,905 mmBOE; proved reserves of subsidiaries totaled ~~6,287~~5,984 mmBOE; Eni’s share of reserves of equity-accounted entities was ~~981~~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 ~~U.S. Securities and Exchange Commission (SEC)~~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 ~~share of production~~equity interest to total proved reserves of the contractual area, ~~in respect of the duration~~until expiration of the relevant mineral right. ~~Proved~~Eni’s proved reserves ~~to which Eni is entitled~~entitlements under PSAs are calculated so that the sale of production entitlements ~~should~~ cover expenses incurred by the Group ~~to develop a~~for field development (Cost Oil) and recognize ~~the Profit Oil~~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) ~~continuously~~ 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.

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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 ~~“Università degli Studi~~“Politecnico di ~~Milano”~~Torino” and received a Master of Science degree in ~~Physics~~Mining Engineering in ~~1988.~~2000. He ~~has more than 30 years of experience~~was appointed in ~~the oil&gas industry~~2020 and has more than 20 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process ~~fulfils~~fulfil the professional qualifications requested by the role and ~~complies~~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 ~~2019,~~2020, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately ~~31%~~36% of Eni’s total proved reserves at December 31, ~~2019~~20204, confirming, as in previous years, the reasonableness of Eni internal evaluation5.

In the ~~2017-2019~~2018-2020 three-year period, ~~86%~~92% of Eni total proved reserves were subject to an independent evaluation. As at December 31, ~~2019, the Zohr field~~2020, Balder in ~~Egypt was~~Norway and Merakes in Indonesia were the main Eni property, which did not undergo an independent evaluation in the last three years. ~~Management expects that the Zohr field will be subject to an independent evaluation in 2020.~~

1

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

2

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.

3

See “Item 19 – Exhibits”.

4

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

5

See “Item 19 – Exhibits”.

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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 ~~128~~80 mmBOE as of December 31, 2020 (128 and 148 mmBOE as of December 31, 2019 ~~(148~~ and ~~178 mmBOE as of December 31,~~ 2018, ~~and 2017,~~ respectively). Said volumes are not included in reserves volumes shown in the table herein.

	Subsidiaries						Equity-accounted entities						Subsidiaries						Equity-accounted entities
(mmBOE)	2019		2018		2017		2019		2018		2017		2020		2019(a)		2018		2020		2019		2018
Revisions of previous estimates		459		590		466		62		(99)		(285)		216		459		590		3		62		(99)
Improved recovery				13		20								5				13
Extensions and discoveries		101		169		483		6						17		101		169		30		6
Purchases of minerals-in-place		30		332		2		184		363						30		332				184		363
Sales of minerals-in-place~~(a)~~		(42)		(528)		(523)		(6)		(1)						(42)		(528)				(6)		(1)
Total additions to proved reserves		548		576		448		246		263		(285)		238		548		576		33		246		263
Production for the year(b)		(617)		(650)		(631)		(62)		(26)		(32)		(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 ~~(622.3 mmboe~~ in ~~2017 and 625.0 mmboe in 2018)~~2019) reflected hydrocarbons volumes of 45.4 mmBOE consumed in operations ~~(35.2~~(43.5 mmBOE in ~~2017~~2018 and ~~43.5~~45.4 mmBOE in ~~2018)~~2019), changes in inventories and other factors.

		Subsidiaries and equity-accounted entities						Subsidiaries and equity-accounted entities
(%)	��	2019		2018		2017		2020		2019		2018
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources			117		124		25		43		117		124
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic			92		100		103		43		92		100

Eni’s proved reserves as of December 31, ~~2019~~2020 totaled ~~7,268~~6,905 mmBOE (liquids ~~3,601~~3,515 mmBBL; natural gas ~~19,832~~18,001 BCF) and included the effect of an updating of the gas conversion factor (up by 67 mmBOE). Eni’s proved reserves reported ~~an increase~~a decrease of ~~115~~363 mmBOE, or ~~1.6%~~5%, from December 31, ~~2018~~2019, as they were negatively affected by a depressed scenario with the crude oil prices decreased to historic lows due to ~~progress made in~~disruptive effects of the ~~year in exploring for~~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 ~~developing new reserves and property acquisitions net of property sales. Portfolio transactions entailed a net addition of 166 mmBOE and comprised: (i)~~ the purchase of ExxonMobil producing and development assets in Norway by our equity-accounted joint venture Vår Energi; (ii) the purchase of a 100% interest of Oooguruk production field in Alaska; (iii) the disposal of our production assets in Ecuador, of a 20% interest at the Merakes discovery in Indonesia,reserve replacement ratio as well as ~~other minor assets~~accelerating the reduction in ~~Norway; and (iv) sales of minerals-in-place of approximately 4 million boe of volumes (mainly gas)~~our existing reserve levels 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.we continue production from our fields.

All sources additions to proved reserves booked in ~~2019~~2020 were ~~794~~271 mmBOE; of which ~~548~~238 mmBOE came from Eni’s subsidiaries, ~~which include sales of reserves as part of a long-term supply agreement as discussed above,~~ while ~~246~~33 mmBOE from Eni’s equity-accounted entities.

~~Due~~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 ~~decrease in~~depressed oil ~~and gas prices compared to~~price environment the Brent reference price used in the reserve estimation process was calculated at ~~$62.7 per~~ 41 $/barrel in 2020, much lower than the 63 $/barrel used in 2019, ~~($71.4 per barrel in 2018),~~leading us to reduce our ~~all sources additions decreased~~proved reserves by 58124 mmBOE, due to the removal of volumes of reserves which have become uneconomical in ~~that environment, which were partially offset by~~this environment. There was also an offsetting positive addition due to net higher ~~volume~~reserves entitlements atunder 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”.

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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 ~~117%~~43% in 2020 (117% in 2019 ~~(124%~~and 124% in ~~2018 and 25% in 2017)~~2018). The organic reserves replacement ratio was ~~92%~~43% in 2020 (92% in 2019 ~~(100%~~and 100% in ~~2018 and 103% in 2017)~~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 ~~10.6~~10.9 years as of December 31, ~~2019,~~2020, which included reserves of both subsidiaries and equity-accounted entities.

Eni’s subsidiaries

Eni’s subsidiaries added ~~548~~238 mmBOE of proved oil and gas reserves in ~~2019~~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 ~~sales~~18 mmBOE described above; (ii) extensions and ~~purchase~~discoveries were up by 17 mmBOE mainly due to the final investment decisions made for the projects of ~~minerals- in- place.~~Mahani in the onshore United Arab Emirates. This ~~comprised 236 mmBBL~~field started up in January 2021; and (iii) improved recovery of ~~liquids~~5 mmBOE related to the Burun field in Turkmenistan.

Further information and ~~1,525 BCF~~explanations of ~~natural gas.~~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 ~~101~~30 mmBOE mainly due to the final investment decisions made for the projects of ~~Dalma~~Bredaiblikk in ~~the offshore United Arab Emirates, Assa North in Nigeria and Agogo field in the offshore operated Block 15/06 in Angola;~~Norway; (ii) revisions of previous estimates were up by 459 mmBOE and mainly derived from the upward revisions of certain gas fields in Nigeria to feed the expansion project of the Bonny liquefaction plant, owned by Nigeria LNG (Eni’s interest 10.4%), and progress in development activities at the Zohr project in Egypt, Kashagan project in Kazakhstan and Berkine North in Algeria; (iii) purchases of mineral-in-place referred to Oooguruk production field in Alaska, as described above; and (v) sales of minerals-in-place referred to the disposal of a 20% stake of the Merakes discovery in Indonesia and entire participation of Ecuador production assets. In addition, 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, as discussed above.

~~Eni’s share of equity-accounted entities~~

Eni’s share of equity-accounted entities added 246 mmBOE of proved oil and gas reserves in 2019 net of sale and purchase minerals-in-place. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates were up by 623 mmBOE mainly due to the progress in development activities at the ~~Balder X field in Norway; (ii) extensions and discoveries were up~~Angola-LNG project (up by 630 mmBOE), partly offset by negative price effects of 24 mmBOE, mainly ~~due~~recorded in Norway, and minor negative revisions for 3 mmBOE.

Further information and explanations of significant changes with respect to ~~the production start-up~~each line item of the ~~Trestakk field~~movements in ~~Norway; (iii) the purchase of ExxonMobil producing~~net proved reserves are provided in Supplemental oil and ~~development assets in Norway, as described above;~~gas information on page F-150 and ~~(v) sales of minerals-in-place referred to the minor producing assets in Norway.~~subsequent pages.

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Proved undeveloped reserves of natural gas amounted to ~~5,415~~4,992 BCF, mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to ~~905~~837 mmBBL of liquids and ~~5,041~~4,703 BCF of natural gas. The table below ~~provide~~provides a summary of changes in total proved undeveloped reserves for ~~2019.~~2020.

Subsidiaries and equity-accounted entities (mmBOE)	~~2019~~
~~Proved undeveloped reserves as of December 31, 2018~~		~~2,309~~
~~Transfers to proved developed reserves~~		~~(655~~)
~~Extensions and discoveries~~		~~101~~
~~Revisions of previous estimates~~		~~327~~
~~Purchases of minerals-in-place~~		44
~~Sales of minerals-in-place~~		~~(12~~)	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

In 2019, total proved undeveloped reserves decreased by 195 mmBOE mainly due to progress made in maturing PUDs to proved developed (655 mmBOE). Additions to PUDs for the year included: (i) extensions and discoveries (up by 101 mmBOE) mainly due to the final investment decisions made for the Dalma project in the United Arab Emirates, the Assa North project in Nigeria and the Agogo field in Angola; (ii) revisions of previous estimates (up by 327 mmBOE) mainly reported in Nigeria due to the final investment decision made for an expansion project of the Bonny liquefaction plant and in Egypt due to the development activity of the Zohr project; (iii) purchases (up by 44 mmBOE) mainly related to the Vår Energi acquisition in Norway as discussed above; and (iv) sales of minerals-in-place (down by 12 mmBOE) related to minor assets in Norway and the Merakes discovery in Indonesia, as mentioned above.

During ~~2019,~~2020, Eni matured ~~655~~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 ~~and Nidoco~~ in ~~North West~~ Egypt, ~~Kashagan~~Zubair in ~~Kazakhstan, Litchendjili in Congo, Ngl Eleme in Nigeria and~~Iraq, Area 1 in ~~Mexico.~~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 ~~2019,~~2020, capital expenditure amounted to approximately ~~€6.8~~€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 ~~approximately~~ 0.5 BBOE of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date and ~~decreased 0.1 BBOE~~unchanged from 2018. The decrease during 2019 was driven mainly by the progress in development activities made at the Kashagan field in Kazakhstan and by the Bahr Essalam phase 2 and Wafa compression projects in Libya.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 ~~(0.1~~(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 ~~(0.3~~(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~~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.

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reserves and supplies from third parties based on existing contracts. Production is expected to account for approximately ~~91%~~93% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, ~~2019.~~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 ~~2019,~~2020, oil and natural gas production available for sale averaged ~~1,736~~1,609 KBOE/d ~~(1,732~~(1,736 KBOE/d in ~~2018)~~2019). Production for the year expressed in barrel-of-oil equivalent was calculated assuming a natural gas conversion factor which was updated to ~~5,408~~5,310 CF of gas equaling 1 barrel of oil without restating the comparative periods (it was ~~5,458~~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 ~~barely unchanged from 2018.~~

~~The full year period results were~~negatively affected by the ~~divestment~~COVID-19 impacts on the global hydrocarbons demands and on the Company’s cash flows. Our production volumes were reduced as a consequence of ~~Eni’s interest~~a reduction in ~~certain assets as well as the effect of the business combination closed at the end of 2018 which involved our former subsidiary Eni Norge which was merged with Point Resources’ assets~~capital expenditures to ~~establish the equity- accounted joint venture Vår Energi,~~develop reserves, OPEC+ mandated production cuts and the termination of the Intisar production contract in Libya from the third quarter of 2018. Excluding the impact of portfolio transactions, marginal price effects at our PSAs and the termination of the Intisar contract, production would have grown by 4%. Production performance was driven by the ramp-up of the Zohr field and of other fields started in 2018, mainly in Libya, Ghana and Angola, and by the 2019 new project start-ups in Mexico, Norway, Egypt and Algeria. Other production increases were reported in Nigeria, as well as Kazakhstan and the United Arab Emirates. These positives were partly offset by lower gas production in Indonesia due to a ~~scale-down in activity reflecting a significant~~ slowdown in gas demand, mainly in ~~Asia,~~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 ~~Venezuela~~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 ~~the current situation in the Country, as well as~~force majeure, and finally by mature fields ~~decline, mainly in Italy and Angola. New field start-ups and ramp-ups of production added an estimated approximately 250 KBOE/d of new production.~~

Production for the year excluded gas volumes which were not lifted by a long-term buyer who nonetheless paid the underlying price as provided by the take-or-pay clause of the long-term supply contract.declines.

Liquids production ~~(890~~(841 KBBL/d) ~~increased~~decreased by 649 KBBL/d, or approximately 1%5% from the full year of ~~2018. Start- ups~~2019. The reduction in Libya, the effects of capex and ~~ramp-ups~~OPEC+ cuts, as well as mature field declines were partially offset by the contribution of ~~the period, mainly in Mexico, Libya and Ghana,~~portfolio activities and production growth in Mexico due to the ~~United Arab Emirates~~ramp-up of Area 1, Angola for the start-up of Agogo, Congo due to the Nenè phase 2B start-up, Algeria and ~~Nigeria were partly offset by facility shutdowns, mainly in Congo, lower production in Venezuela and mature fields decline.~~Kazakhstan.

Natural gas production ~~(4,576~~(4,077 mmCF/d) decreased by 54499 mmCF/d, or approximately 1%11% compared to the full year of ~~2018.~~2019. Lower production in ~~Indonesia~~Libya and ~~Venezuela~~the impact of lower natural gas demand in certain areas (mainly in Egypt), as well as ~~mature fields decline~~lower LNG demand were partly offset by ~~production ramp-ups of the period, mainly in Egypt and Ghana, and~~ the growth in ~~Nigeria.~~Algeria due to the start-up of the Berkine gas project and in Kazakhstan.

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~~kilometers. Relinquishment~~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 ~~year~~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 ~~licenses related mainly to India, China,~~Asia, in particular in Oman, Russia, Vietnam ~~Portugal, Ecuador~~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 ~~United Kingdom covering an~~planned activities. Management believes that a significant amount of acreage ~~of approximately 27,600 square kilometers. Partial relinquishment were reported mainly in Indonesia, South Africa and Pakistan~~will be maintained following extension or ~~interest reduction mainly in Oman, Morocco, Cyprus, Indonesia and Mozambique for approximately 55,500 square kilometers.~~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, ~~2019.~~2020. A gross acreage is one in which Eni owns a working interest.

~~December 31,~~
~~2018~~

~~December 31, 2019~~

~~Total net~~
~~acreage~~ ~~(a)~~

~~Number~~
of
~~interests~~

~~Gross~~
~~developed~~
~~acreage~~ ~~(a) (b)~~

~~Gross undeveloped~~
~~acreage~~ ~~(a)~~

~~Total~~
~~gross~~
~~acreage~~ ~~(a)~~

~~Net~~
~~developed~~
~~acreage~~ ~~(a) (b)~~

~~Net~~
~~undeveloped~~
~~acreage~~ ~~(a)~~

~~Total net~~
~~acreage~~ ~~(a)~~

~~EUROPE~~

~~46,332~~

~~309~~

~~15,282~~

~~58,616~~

~~73,898~~

~~9,278~~

~~28,750~~

~~38,028~~

~~Italy~~

~~14,987~~

~~128~~

~~9,545~~

~~7,595~~

~~17,140~~

~~7,887~~

~~5,845~~

~~13,732~~

~~Rest of Europe~~

~~31,345~~

~~181~~

~~5,737~~

~~51,021~~

~~56,758~~

~~1,391~~

~~22,905~~

~~24,296~~

~~Cyprus~~

~~17,111~~

7

~~26,614~~

~~14,557~~

~~Greenland~~

~~1,909~~

2

~~4,890~~

~~1,909~~

~~Montenegro~~

~~614~~

1

~~1,228~~

~~614~~

~~Norway~~

~~2,628~~

~~131~~

~~4,828~~

~~14,577~~

~~19,405~~

~~777~~

~~3,436~~

~~4,213~~

~~Portugal~~

~~3,182~~

~~United Kingdom~~

~~4,018~~

~~38~~

~~909~~

~~1,011~~

~~1,920~~

~~614~~

~~506~~

~~1,120~~

~~Other Countries~~

~~1,883~~

2

~~2,701~~

~~1,883~~

~~AFRICA~~

~~165,699~~

~~260~~

~~54,351~~

~~273,494~~

~~327,845~~

~~15,194~~

~~148,431~~

~~163,625~~

~~North Africa~~

~~33,932~~

~~69~~

~~17,628~~

~~51,716~~

~~69,344~~

~~7,966~~

~~23,907~~

~~31,873~~

~~Algeria~~

~~1,155~~

~~47~~

~~12,157~~

~~279~~

~~12,436~~

~~5,472~~

~~100~~

~~5,572~~

~~Libya~~

~~13,294~~

~~11~~

~~1,963~~

~~24,673~~

~~26,636~~

~~958~~

~~12,336~~

~~13,294~~

~~Morocco~~

~~17,925~~

1

~~23,900~~

~~10,755~~

~~Tunisia~~

~~1,558~~

~~10~~

~~3,508~~

~~2,864~~

~~6,372~~

~~1,536~~

~~716~~

~~2,252~~

~~Egypt~~

~~5,248~~

~~56~~

~~5,659~~

~~15,710~~

~~21,369~~

~~2,113~~

~~5,500~~

~~7,613~~

~~Sub-Saharan Africa~~

~~126,519~~

~~135~~

~~31,064~~

~~206,068~~

~~237,132~~

~~5,115~~

~~119,024~~

~~124,139~~

~~Angola~~

~~5,303~~

~~45~~

~~8,349~~

~~7,841~~

~~16,190~~

~~1,073~~

~~2,671~~

~~3,744~~

~~Congo~~

~~1,471~~

~~25~~

~~1,430~~

~~1,320~~

~~2,750~~

~~843~~

~~628~~

~~1,471~~

~~Gabon~~

~~4,107~~

4

~~4,107~~

~~Ghana~~

~~579~~

3

~~226~~

~~1,127~~

~~1,353~~

~~100~~

~~479~~

~~579~~

~~Ivory Coast~~

~~2,905~~

5

~~4,921~~

~~3,724~~

~~Kenya~~

~~43,948~~

6

~~50,677~~

~~43,948~~

~~Mozambique~~

~~978~~

~~10~~

~~25,304~~

~~4,349~~

~~Nigeria~~

~~7,722~~

~~32~~

~~21,059~~

~~8,631~~

~~29,690~~

~~3,099~~

~~3,543~~

~~6,642~~

~~South Africa~~

~~26,202~~

1

~~55,677~~

~~22,271~~

~~Other Countries~~

~~33,304~~

4

~~46,463~~

~~33,304~~

~~ASIA~~

~~181,414~~

~~69~~

~~12,686~~

~~267,851~~

~~280,537~~

~~3,199~~

~~139,497~~

~~142,696~~

~~Kazakhstan~~

~~1,543~~

8

~~2,391~~

~~5,124~~

~~7,515~~

~~442~~

~~1,718~~

~~2,160~~

~~Rest of Asia~~

~~179,871~~

~~61~~

~~10,295~~

~~262,727~~

~~273,022~~

~~2,757~~

~~137,779~~

~~140,536~~

~~Bahrain~~

1

~~2,858~~

~~China~~

~~5,228~~

6

~~77~~

~~13~~

~~India~~

~~5,244~~

~~Indonesia~~

~~23,769~~

~~13~~

~~2,605~~

~~20,898~~

~~23,503~~

~~1,029~~

~~14,926~~

~~15,955~~

~~Iraq~~

~~446~~

1

~~1,074~~

~~446~~

~~Lebanon~~

~~1,461~~

2

~~3,653~~

~~1,461~~

~~Myanmar~~

~~13,558~~

4

~~24,080~~

~~14,147~~

~~Oman~~

~~77,146~~

1

~~90,760~~

~~49,918~~

~~Pakistan~~

~~5,786~~

~~12~~

~~3,390~~

~~8,370~~

~~11,760~~

~~872~~

~~2,907~~

~~3,779~~

~~Russia~~

~~17,975~~

2

~~53,930~~

~~17,975~~

~~Timor Leste~~

~~1,230~~

4

~~2,612~~

~~1,620~~

~~Turkmenistan~~

~~180~~

1

~~200~~

~~180~~

~~United Arab Emirates~~

~~1,472~~

9

~~2,949~~

~~17,058~~

~~20,007~~

~~217~~

~~10,170~~

~~10,387~~

~~Vietnam~~

~~23,132~~

4

~~23,908~~

~~18,553~~

~~Other Countries~~

~~3,244~~

1

~~14,600~~

~~3,244~~

~~AMERICAS~~

~~9,303~~

~~229~~

~~2,299~~

~~17,763~~

~~20,062~~

~~1,024~~

~~9,679~~

~~10,703~~

~~Ecuador~~

~~1,985~~

~~Mexico~~

~~3,000~~

~~10~~

~~14~~

~~5,455~~

~~5,469~~

~~14~~

~~3,092~~

~~3,106~~

~~United States~~

~~2,191~~

~~205~~

~~1,024~~

~~1,683~~

~~2,707~~

~~513~~

~~1,422~~

~~1,935~~

~~Venezuela~~

~~1,066~~

6

~~1,261~~

~~1,543~~

~~2,804~~

~~497~~

~~569~~

~~1,066~~

~~Other Countries~~

~~1,061~~

8

~~9,082~~

~~4,596~~

~~AUSTRALIA AND OCEANIA~~

~~3,757~~

6

~~728~~

~~2,860~~

~~3,588~~

~~588~~

~~2,214~~

~~2,802~~

~~Australia~~

~~3,757~~

6

~~728~~

~~2,860~~

~~3,588~~

~~588~~

~~2,214~~

~~2,802~~

~~Total~~

~~406,505~~

~~873~~

~~85,346~~

~~620,584~~

~~705,930~~

~~29,283~~

~~328,571~~

~~357,854~~

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- Eni operates under Production Sharing ~~Agreement (PSA)~~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~~service contracts.

Eni’s exploration and production activities are regulated by PSA or ~~scheme~~ 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. In addition, Eni’s activities are regulated by service contract in one block in Nigeria and in Ecuador. In Australia, the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area – JPDA) are regulated by PSAs. 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 3130 onshore and 6358 offshore productive ~~concessions as well as 13 onshore and 9 offshore exploration licenses.~~concessions. Exploration activities have been substantially abandoned in recent years. In ~~2019,~~2020, Italy accounted for approximately 7%6% of Eni’s total worldwide production of oil and natural gas.

In 2020, 36% of Eni’s domestic production ~~in 2019 was accounted for 39%~~derived from fields in the Adriatic and Ionian Seas, ~~47% in~~48% from the Central Southern Apennines and approximately 10% infrom Sicily.

~~Development~~In the Adriatic Sea, activities in ~~2019~~2020 mainly ~~concerned: (i)~~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 ~~Adriatic Sea; (ii)~~year in compliance with applicable Italian laws; a total of five offshore platforms are currently in the ~~progress in development~~authorization process to be removed.

Yearly maintenance and production optimization activities ~~at the Argo and Cassiopea operated projects (Eni’s interest 60%); and (iii) the completion of a digital transformation program at the Viggiano Oil Center~~were completed in the Val d’Agri ~~concession with improvement in environmental standards and plant safety as well in operational performance.~~concession.

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

In Italy, a new law ~~has been~~was enacted effective February 12, 2019, which requires Italian administrative bodies to adopt a plan ~~indented~~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 ~~expects~~expect any material impacts on the ~~Group~~Group’s future results of operations and cash ~~flow.~~flow as well as on the volumes of booked reserves from the enactment of this law. Currently, ~~thirty-three~~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 ~~authorities~~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.

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Libya. Currently, Libya represents approximately ~~16%~~10% of the Group’s total production. ~~Notwithstanding,~~At the ~~complexity~~beginning of 2020 oil export terminals in the Eastern and Southern part of Libya were blocked halting

[MISSING IMAGE: tm215953d3-mp_libya4c.jpg]

most of the ~~geopolitical environment, in 2019 Eni’s activities~~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

~~progressed smoothly~~ 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 ~~achieving~~production resumed at the ~~planned production mainly from Wafa production optimization activities~~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 ~~new compression, upgrading of treatment plants~~uncertainty to Eni’s operations in the ~~Mellitah area~~Country and ~~Sabratha platform,~~to the Group results of operations and ~~completion of Bahr Essalam phase 2. The worsening of the situation in Libya remains an area of issue.~~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 ~~optimization at~~start-up of three productive wells.

Exploration activity yielded positive results with the ~~producing concessions to mitigate mature fields declines.~~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 ~~2019,~~2020, Egypt accounted for ~~19%~~17% of Eni’s total worldwide production of oil and natural gas, the largest contributor to the Company overall production level.

In ~~February 2019, Eni was awarded two onshore~~2020 the award of the exploration ~~blocks: (i) a 100% interest in the South East Siwa~~ block ~~in the Western Desert nearby to the South West Meleiha concession; and (ii) the operatorship with a 50% interest in the~~ West Sherbean ~~block~~(Eni’s interest 50%) in the onshore Nile Delta ~~nearby to the operated Nooros producing fields (Eni’s interest 75%).~~was ratified.

In ~~2019~~2020 development activities ~~were completed:~~concerned: (i) at the ~~Nooros field with~~drilling of infilling wells in the ~~installation of a new gas pipeline to~~production fields located in the ~~El Gamil treatment plant to production optimization and reserves’ recovery maximization; (ii) at the Baltim South West offshore project~~Sinai area (Eni operator with a ~~50%~~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 ~~start-up. Development activities concerned~~in the ~~installation of a production platform and the pipeline to the Abu Madi treatment plant; and (iii) at the~~Arcadia South, Meleiha (Eni’s interest 76%), South West Meleiha (Eni’s interest 100%) ~~production area~~; (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 ~~installation~~onshore and offshore facilities of ~~a pipeline connecting to~~ the ~~Meleiha operated treatment plant.~~Sinai, Western Desert and Mediterranean assets.

In ~~2019,~~2020, production at the Zohr field averaged approximately ~~143~~131 KBOE/d net to Eni.

Development activities ~~to ramp-up production~~progressed during the year at the Shorouk concession where the Zohr gas offshore field ~~(Eni operator~~is located, targeting to ramp up the field production capacity with a ~~50% interest) concerned: (i)~~view of addressing the ~~completion~~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 ~~remaining three~~subsea facilities and of the onshore treatment units reaching a total of eight units; (ii) the drilling and production start-up of additional four wells; and (iii) the completion and entry into operation of a second gas pipeline which increased installed capacity to more than 3.2 BCF/d.plant progressed.

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

As of December 31, ~~2019,~~2020, the aggregate development costs incurred by Eni for developing the Zohr project and capitalized in the financial statements amounted to ~~$5.4~~$5.5 billion (€ ~~4.8~~4.5 billion at the EUR/USD exchange rate of December 31, ~~2019)~~2020). Development expenditure incurred in the year were €1.1 billion. Going forward, planned capital expenditure to support continuing production ramp-up at the Zohr field will be funded through net cash provided by operating activities at the Eni Brent crude marker scenario.€73 million.

As of December 31, ~~2019,~~2020, Eni’s proved reserves booked at the Zohr field amounted to ~~807~~771 mmBOE. The Zohr proved reserves, both developed and undeveloped, related solely to the project phase 1.

~~Development activities at other Eni’s fields in Egypt concerned infilling activities and production optimization in: (i)~~In 2020, the ~~Sinai concession (Eni operator with~~Zohr reserves were subject to an 100% interest), including the production start-up achieved at the recent discoveries as well as water injection optimization to support reservoir pressure; and (ii) the operated Meleiha (Eni’s interest 76%), Meleiha Deep (Eni’s interest 100%) and Ras Qattara (Eni’s interest 75%) concessions in the Western Desert.independent evaluation.

Exploration activities yielded positive results ~~with: (i) a gas discovery~~with near-field discoveries in the ~~El Qar’a exploration license~~operated areas: (i) the Nidoco NW-1 in the Abu Madi West concession (Eni’s interest 75%)~~, located~~ and Bashrush gas discoveries (Eni’s interest 37.5%) in the ~~Nile Delta;~~Great Nooros Area; (ii) the ~~Sidri~~SWM-A-6X oil discovery ~~in the Abu Rudeis development lease (Eni’s interest 100%), in the Gulf of Suez. Drilling activity has been completed and~~

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In ~~January~~ 2020 Eni was awarded the operatorship with a 60% interest in the offshore Block 28, ~~as operator.~~

~~In November 2019 Eni~~in the Namibe basin, and ~~the Country’s Authority signed~~ a ~~Memorandum of Understanding which provides for the acquisition of the offshore Block 1/14 (Eni operator with a 35% interest) and~~42.5% interest in the onshore Cabinda ~~Center block (Eni’s interest 42.5%).~~Central block.

~~In 2019 Eni finalized an extension of exploitation rights until 2032 of Block 15 (Eni’s interest 20%),~~During the ~~number of the Development Areas has been reduced, joining some of them together.~~

~~Development activities concerned: (i) the completion of the planned activities at the Vandumbu field in the West Hub project~~year, in the operated Block 15/06 (Eni’s interest 36.84%)~~; and (ii)~~, production ~~optimization~~ramp-up was achieved at the ~~Mpungi and Sangos fields~~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 ~~in some fields in~~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 014 (Eni’s interest ~~9.8%~~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 ofat the Angola LNG venture, which runs ~~the~~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 of LNG.~~y. In ~~2019~~2020 production net to Eni averaged approximately 2220 KBOE/d. In October 2019 Eni, as operator of a new joint venture (Eni interest 25.6%), signed a commercial agreement with the partners of the Angola LNG for the development of the gas fields to support the liquefaction plant. The first development project is expected to be sanctioned in 2020.

Exploration activities ~~progressed at~~yielded positive results in the operated Block 15/06, ~~during the year, after resumed in 2018. Eni made~~following a ~~promising discoveries with the Agogo oil~~successful appraisal well ~~and the Agogo~~ -2 and Agogo-3 appraisal wells, then with the Ndungu and the Agidibo oil wells. These discoveries will undergo phased development in accordance to the production capacity of the two FPSO units installed in the area. In 2020 the production start-up of the Agogo ~~discovery~~discovery. The Block 15/06 exploration license was ~~achieved.~~renewed for additional three years.

~~Mozambique.~~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 of~~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 infor 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

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

Nigeria. In ~~May 2019~~January 2021, Eni ~~completed~~and the ~~purchase of a 10%~~partners divested the onshore production and development block OML 17 (Eni’s interest 5%).

Development activities of the ~~deep~~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 ~~A5-B, Z5-C~~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 ~~Z5-D blocks from ExxonMobil.~~

~~In July 2019 Eni divested a 25.5%~~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 ~~A5-A block to Qatar Petroleum. Following this acquisition Eni retains the operatorship with a 34% interest.~~Bonga field (Eni’s interest 12.5%).

~~Nigeria~~. 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 ~~agreements~~agreement from the SPDC JV (Eni’s interest 5%), TEPNG JV and the NAOC JV (Eni’s interest 20%). In ~~2019,~~2020, the Bonny liquefaction plant processed approximately ~~1,165~~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. In December 2019 the final investment decision was sanctioned for the construction of an additional treatment unit which will increase production capacity until 30 mmtonnes/y of LNG. Development activity is expected to be completed in 2024 with production start-up.

Development activities of the operated OMLs 60, 61, 62 and 63 blocks (Eni’s interest 20%) concerned: (i) the completion of planned activities and production start-up of the Obiafu 41 gas and condensates discovery; and (ii) increasing generation capacity of the combined cycle power plant at Okpai to achieve about 1 GW from the actual a 480 MW. Natural gas production of the area will support the plant capacity.

Other development activities concerned: (i) infilling program and production optimization in the OML 118 block (Eni’s interest 12.5%); (ii) the completion of drilling activities of two additional oil wells at the Abo field in the operated OML 125 block (Eni’s interest 100%). Peak production of 26 KBBL/d has been achieved during the year; (iii) the completion of the associated gas project in the OML 43 block (Eni’s interest 5%) and the SSAGS project in the OML 28 block (Eni’s interest 5%). Associated gas production will be sold in the domestic market; and (iv) the flaring down Assa North project (Eni’s interest 5%) has been sanctioned to support the domestic market.

The acquisition of the OPL 245 property made by Eni in 2011 is the subject of certain judicial proceedings ~~describe~~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 ~~2019,~~2020, Kazakhstan accounted for 8%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 ~~over~~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 ~~2019,~~2020, production at the Kashagan field averaged 5356 KBBL/d of liquids and 5452 mmCF/d of natural gas net to Eni. ~~The treated gas is~~Gas volumes undergo a treatment and then are delivered to the national gas marketing and transportation company (KazTransGas)~~, and~~; a part of the ~~remaining~~gas volumes is utilized as fuel gas. ~~The remaining untreated~~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 ~~for~~ 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 ~~conversion~~existing facilities; and (ii) delivering a part of ~~production wells into injection wells, the debottlenecking and the revamping of existing facilities with the construction of~~gas volumes to a new onshore ~~gas~~ treatment ~~plant. A final investment decision has yet to be made.~~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~~long-time horizon, ~~and subsequently to the production start-up,~~ management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures.

As of December 31, ~~2019,~~2020, Eni’s proved reserves booked for the Kashagan field amounted to ~~661~~675 mmBOE, increased from ~~614~~661 mmBOE in ~~2018.~~2019.

As of December 31, ~~2019,~~2020, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $10 billion (€~~8.9~~8.1 billion at the EUR/USD exchange rate of December 31, ~~2019)~~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. ~~Cost~~Costs incurred in the year were ~~€106~~€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 ~~2019,~~2020, production of the Karachaganak field averaged 4653 KBBL/d of liquids and ~~186~~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,~~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 ~~progressed; (ii) project of~~and the construction of a fourth gas ~~re-injection unit was sanctioned~~reinjection unit; and ~~activity started up during the year; and (iii)~~(ii) completion of the Front End Engineering Design of the Karachaganak Expansion Project ~~has been completed.~~(KEP). This latter project is scheduled to be achieved in several phases. The ~~planned activities include~~development program of the ~~installation~~first phase, sanctioned at the end of ~~two~~2020, provides the construction of a sixth injection line, the drilling of three additional injection wells and of a new gas ~~re-injection facility.~~compression unit. Start-up is expected in 2024.

As of December 31, ~~2019,~~2020, Eni’s proved reserves booked for the Karachaganak field amounted to 507 mmBOE, increased from 448 mmBOE ~~slightly decreased from 452 mmBOE~~ in ~~2018.~~2019.

As of December 31, ~~2019,~~2020, the aggregate costs incurred by Eni for the Karachaganak project capitalized in the financial statements amounted to ~~$4.1~~$4.3 billion (€~~3.7~~3.5 billion at the EUR/USD exchange rate of December 31, ~~2019)~~2020). ~~Cost~~Costs incurred in the year were ~~€267~~€147 million.

Rest of Asia

Eni’s operations in Rest of Asia are conducted mainly in Indonesia, Iraq and United Arab Emirates. In ~~2019,~~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.

~~Indonesia~~Pakistan.~~. Activities are concentrated~~ In March 2021, Eni signed an agreement to divest the entire upstream activity in the ~~offshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds~~Country including interests in ~~13 blocks.~~

eight development and production licenses to Prime International Oil&Gas local company. In ~~2019, Eni divested to Neptune a 20%~~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 ~~East Sepinggan block, offshore East Kalimantan, which includes the Merakes field~~Latif (Eni’s interest 33.3%), Zamzama (Eni’s interest 17.75%) and ~~the East Merakes discovery. Eni will retain a 65%~~Sawan (Eni’s interest ~~and the operatorship.~~

~~In 2019 Eni was awarded the West Ganal exploration block (Eni operator with a 40% interest) located in the deep water Kutei Basin, effective since January 1, 2020.~~

~~Development activities concerned the offshore Merakes gas project in the operated East Sepinggan block.~~23.7%) fields.

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United Arab ~~Emirates~~Emirates.. In ~~2019,~~2020, Eni ~~awarded: (i)~~awarded the operatorship ~~of the Block 1 and 2~~ with a 70% interest in the Block 3, located offshore Abu Dhabi. The exploration

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commitment for the first phase ~~consists in~~includes exploration studies, ~~for the Block 1 and~~ the drilling of ~~two~~ exploration ~~wells~~ and ~~one~~ appraisal ~~well~~wells.

In January 2021, production start-up was achieved at the Mahani field located in ~~the Block 2; (ii) three~~ onshore ~~exploration~~

~~concessions~~concession of Area B (Eni’s interest 50%) in the Emirate of Sharjah, ~~with a 75% interest in~~just one year since discovery and two years after signing the ~~operated~~ concession ~~Area A and C and a 50% interest in the participated concession Area B. In January 2020, exploration~~agreement. Development activities, ~~yielded positive results~~sanctioned with the ~~Mahani-1 gas and condensates discovery in the Area B concession; and (iii) the operatorship with a 90% interest in the Block A, located offshore Emirate of Ras al Khaimah.~~

~~Development activities concerned: (i) the Dalma Gas Development project in the Gasha concession (Eni’s interest 25%). The~~ final investment decision, ~~was sanctioned. Start-up is expected in 2022; and (ii)~~provide the ~~Nasr Full Field Development project in~~progressive ramp-up with the ~~Umm Shaif/Nasr concession (Eni’s interest 10%). The program was completed and production ramp-up achieved in the year.~~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 ~~2019,~~2020, Eni’s operations in the Americas area accounted for approximately 6%7% of its total worldwide production of oil and natural gas.

~~Ecuador. In 2019, Eni divested its~~Mexico. The development activities inmainly concern the ~~country.~~

~~Mexico.~~ ~~In 2019 production start-up was achieved at~~full field development program of the operated license Area 1 ~~license~~ (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 ~~drilling of two wells and the~~ installation of a new leased production platform, ~~which is linked by a sealine to~~currently under construction, as well as the conversion and upgrading of an ~~onshore treatment unit. The full field development envisages a phased installation of three additional platforms and a~~ FPSO unit ~~which~~that will ~~increase~~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 ~~capacity up to 100 KBBL/d in 2021.~~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.~~States. Eni ~~holds~~holds: (i) interests in 4148 exploration and production blocks in the Gulf of Mexico, of which ~~18 are operated by Eni. Eni also holds~~16 as operator; (ii) interests and operates ~~151~~84 blocks in ~~Alaska with 100% working interest.~~Alaska; and (iii) Alliance area in Texas.

~~During 2019 the net production of Eni in the Unites States has significantly increased by 20%, from 50 KBOE/d to 60 KBOE/d, as a result of an intense activity of production optimization.~~

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Venezuela. In ~~2019,~~2020, Eni’s production of oil and natural gas averaged 3841 KBOE/d and accounted for approximately 2%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.~~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.~~country. For further information on this matter, see “Item 3 –— Risk factors – Political considerations”.

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


Natural gas supply	2019		2018		2017
Natural gas supply							2020		2019		2018
	(BCM)						(BCM)
Italy		5.44		5.33		5.05		7.47		5.57		5.46
Outside Italy		65.21		68.82		73.23		54.69		64.85		68.67
Russia		24.71		26.24		28.09		22.49		24.36		26.10
Algeria (including LNG)		6.66		12.02		13.18		5.22		6.66		12.02
Libya		5.86		4.55		4.76		4.44		5.86		4.55
the Netherlands		4.12		3.95		5.20		1.11		4.12		3.95
Norway		6.43		6.75		7.48		7.19		6.43		6.75
the United Kingdom		1.75		2.21		2.36		1.62		1.75		2.21
Indonesia (LNG)		1.58		3.06		0.74		1.15		1.58		3.06
Qatar (LNG)		2.79		2.56		2.36		2.47		2.79		2.56
Other supplies of natural gas		7.91		5.52		6.75		5.24		7.90		5.50
Other supplies of LNG		3.40		1.96		2.31		3.76		3.40		1.97
Total supplies of subsidiaries		70.65		74.15		78.28		62.16		70.42		74.13
Withdrawals from (input to) storage		0.08		0.08		0.31		0.52		0.08		0.08
Network losses, measurement differences and other changes		(0.22)		(0.18)		(0.45)		(0.03)		(0.22)		(0.18)
Volumes available for sale of Eni’s subsidiaries		70.51		74.05		78.14		62.65		70.28		74.03
Volumes available for sale of Eni’s affiliates		2.56		2.66		2.69		2.34		2.57		2.57
Total volumes available for sale		73.07		76.71		80.83		64.99		72.85		76.60

Sales of natural gas

Eni is selling gas to wholesale ~~and retail~~ 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. The retail segment includes sales to residential customers (households and larger accounts like hospitals, schools, office buildings) and small and medium-sized businesses located in urban areas. The Company has grown the combined offer of gas and electricity to retail customers to maximize cross-selling opportunities and cost synergies.

In ~~2019,~~2020, natural gas sales amounted to ~~73.07~~64.99 BCM (including Eni’s own consumption and Eni’s share of sales made by equity-accounted entities), representing a decrease of ~~3.64~~7.86 BCM, or ~~4.7%~~10.8% from the previous year. Sales in Italy ~~(37.85~~(37.30 BCM) decreased by 3%1.8% from ~~2018.~~2019. Lower sales to ~~wholesalers, spot market~~thermoelectrical and ~~residential segment~~industrial segments were partly offset by higher sales to ~~thermoelectrical and industrial segments.~~hub. Sales in the European markets amounted to ~~22.70~~19.33 BCM, a decrease of ~~12.7%~~13.5% or ~~3.30~~3.02 BCM from ~~2018.~~2019.

Sales to long-term buyers were ~~4.37 BCM; up~~3.67 BCM, down by ~~27.8%~~16% compared to the previous year ~~thanks~~due to the ~~higher~~lower availability of Libyan output.

Sales in the Extra European markets ~~(8.15~~(4.69 BCM) decreased by ~~0.11~~3.46 BCM or ~~1.3%~~42.5% due to lower LNG sales in the United States and in the Far East ~~markets, partly offset by higher volumes sold in the United States.~~markets.

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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 ~~Japan.~~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
2019 2018 2017

(BCM)

Europe 5.5 4.7 5.2
Extra European markets 4.6 5.6 3.1
10.1 10.3 8.3

~~Electricity sales and power generation~~

~~Electricity sales~~

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 Stock Exchange for electricity and at industrial sites. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value chain leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and small and middle business located in urban area, the Company has developed a commercial offer that provides the combined supply of gas and power to the retail market in Italy and in France.

In 2019, power sales (39.49 TWh) were directed to the free market (72%), the Italian Power Exchange (18%), industrial sites (9%) and others (1%). Compared to 2018, electricity sales in the free market were up by 2.40 TWh or by 9.3%, due to higher volumes sold to wholesalers, middle market and retail segments, partially offset by lower volumes sold to the large customers.

Power availability
2019 2018 2017

(TWh)

Power generation sold 21.66 21.62 22.42
Trading of electricity(a)
17.83 15.45 12.91
39.49 37.07 35.33
Power sales by market
Free market(a)
28.31 25.91 26.53
Italian Exchange for electricity 7.27 7.17 5.21
Industrial plants 3.38 3.49 3.01
Other(a) 0.53 0.50 0.58
39.49 37.07 35.33

~~(a)~~

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

~~Power generation~~

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. In 2019, power generation was 21.66 TWh, substantially in line with 2018. As of December 31, 2019, installed operational capacity was 4.7 GW, unchanged compared to December 31, 2018.

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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.

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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 ~~equipments~~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 to supply~~d. The refinery supplies Eni’s distribution network in the country.

In the UAE, Eni and ADNOC signed a Share Purchase Agreement to enable Eni to acquire from ADNOC a 20% equity interest in ADNOC Refining. ADNOC Refining operates two refineries in Ruwais (Ruwais East and Ruwais West) and another in Abu Dhabi (Abu Dhabi Refinery), with a total refining capacity of 922 KBBL/d.

Biorefineries

Ownership
share
(%)

Capacity
(2019)(a)
(ktonnes/y)

Capacity
(at regime)
(ktonnes/y)

Throughput
(2019)
(ktonnes/y)

Wholly-owned
Venezia 100 360 560 217
Gela 100 300 750 94
Total biorefineries 660 1,310 311

~~(a)~~

~~Includes the pro-rata of installed capacity of Gela’s biorefinery (720,000 tonnes/y) started in August 2019.~~

~~Biorefining~~

	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 ~~360 ktonnes/~~0.4 mmtonnes/y, leverages on the ~~Ecofining~~TMEcofining™ proprietary technology to transform vegetable oil ininto hydrogenated bio-fuels. A second phase of development is ~~underway.~~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 ~~normative~~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 ~~reconversion~~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 ~~with an installed capacity of 720,000 tonnes/y and~~ equipped with the ~~Ecofining~~TMEcofiningTM 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
	2019		2018		2017
Availability of refined products							2020		2019		2018
	(mmtonnes)						(mmtonnes)
ITALY
Refinery throughputs
At wholly-owned refineries		17.26		16.78		16.03		12.72		17.26		16.78
Less input on account of third parties		(1.25)		(1.03)		(0.34)		(1.75)		(1.25)		(1.03)
At affiliated refineries		4.69		4.93		5.46		3.85		4.69		4.93
Refinery throughputs on own account		20.70		20.68		21.15		14.82		20.70		20.68
Consumption and losses		(1.38)		(1.38)		(1.36)		(0.97)		(1.38)		(1.38)
Products available for sale		19.32		19.30		19.79		13.85		19.32		19.30
Purchases of refined products and change in inventories		7.27		7.50		6.74		7.18		7.27		7.50
Products transferred to operations outside Italy		(0.68)		(0.54)		(0.46)		(0.66)		(0.68)		(0.54)
Consumption for power generation		(0.35)		(0.35)		(0.34)		(0.35)		(0.35)		(0.35)
Sales of products		25.56		25.91		25.73		20.02		25.56		25.91
Biorefinery throughputs		0.31		0.25		0.24		0.71		0.31		0.25
OUTSIDE ITALY
Refinery throughputs on own account		2.04		2.55		2.87		2.18		2.04		2.55
Consumption and losses		(0.18)		(0.20)		(0.22)		(0.17)		(0.18)		(0.20)
Products available for sale		1.86		2.35		2.65		2.01		1.86		2.35
Purchases of finished products and change in inventories		4.17		4.12		4.36		3.39		4.17		4.12
Products transferred from Italian operations		0.68		0.54		0.46		0.66		0.68		0.54
Sales of products		6.71		7.01		7.47		6.06		6.71		7.01
Refinery throughputs on own account		22.74		23.23		24.02		17.00		22.74		23.23
of which: refinery throughputs of equity crude on own account		4.24		4.14		3.51		3.55		4.24		4.14
Total sales of refined products		32.27		32.92		33.20		26.08		32.27		32.92
Crude oil sales		0.44		0.28		0.86		0.67		0.44		0.28
TOTAL SALES		32.71		33.20		34.06		26.75		32.71		33.20

In ~~2019,~~2020, Eni’s refining throughputs on own account in Europe were ~~22.74~~17 mmtonnes, ~~slightly~~ decreased by ~~2.1%~~25.2% from ~~2018,~~2019, due ~~to:~~to the lower throughputs ~~at the Bayernoil refinery,~~processed in Italy as a result of the ~~unavailability~~depressed refining scenario and storage saturation as a consequence of the ~~Vohburg facility in the early nine months~~impact of ~~the year following the event occurred in September 2018, the adverse climatic events at the Milazzo refinery, as well as the participated PCK refinery, affected by the Druzhba pipeline contamination.~~COVID-19 on demand. These negatives were partially offset by ~~higher volumes processed by~~ the ~~Taranto refinery following lower maintenance standstills.~~restart of some plants in Vohburg and PCK (maintenance turnaround in 2019) in Germany.

In Italy, the refinery throughputs ~~(20.70~~(14.82 mmtonnes) ~~were in line with 2018;~~decreased by 28.4% from 2019 following the lower volumes processed at refineries affected by higher maintenance standstills, logistic issues due to adverse climatic events and the upset at the Milazzo refinery, as well as the lower throughputs at the Livorno refinery to counteract the scenario, were offset by higher volumes processed at the Taranto refinery leveraging on fewer shutdowns.depressed refining scenario.

Outside Italy, Eni’s refining throughputs on own account were ~~2.04~~2.18 mmtonnes, ~~down~~up by approximately ~~510~~140 ktonnes or ~~20%~~6.9% due to the ~~above mentioned downtime~~abovementioned restart of ~~the Bayernoil refinery.~~Vohburg plant and PCK in Germany. Total throughputs in wholly-owned refineries were ~~17.26~~12.72 mmtonnes, updown by ~~0.48~~4.54 mmtonnes or ~~2.9%~~26.3% compared with ~~2018.~~2019.

The refinery utilization rate, ratio between throughputs and refinery capacity, is ~~88%~~69%.

Approximately ~~18.9%~~21.2% of processed crude was supplied by Eni’s Exploration & Production segment, increasing by ~~18.3%~~18.9% from ~~2018.~~2019.

The volumes of biofuels ~~produced~~processed from vegetable oil increased by ~~22.9%~~0.40 mmtonnes compared to ~~2018, driven by~~2019, due to the ~~start-up~~ramp-up of the Gela ~~biorefinery in August 2019, where full production ramp-up is underway, while the Venice biorefinery has been hit by unplanned downtime.~~bio-refinery.

Logistics

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

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Eni also owns a network of oil and refined products pipelines extending approximately ~~1.154~~1.156 kilometers. ~~Eni~~Eni’s logistic model is organized in four hubs (Northern depots, Central depots, Southern depots and Pipeline) ~~and one subsidiary (Petroven), 100% owned since December 2019.~~. 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 57 different logistic joint ventures (Sigemi, Seram, Disma, Seapad, ~~Toscopetrol)~~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	2019		2018		2017
Oil products sales in Italy and outside Italy							2020		2019		2018
	(mmtonnes)						(mmtonnes)
Italy
Retail		5.81		5.91		6.01		4.56		5.81		5.91
Wholesale		7.68		7.54		7.64		5.75		7.68		7.54
		13.49		13.45		13.65		10.31		13.49		13.45
Petrochemicals		0.83		0.96		0.86		0.61		0.83		0.96
Other sales		11.24		11.5		11.22		9.10		11.24		11.50
Total		25.56		25.91		25.73		20.02		25.56		25.91
Outside Italy
Retail		2.44		2.48		2.53		2.05		2.44		2.48
Wholesale		3.11		3.29		3.48		2.88		3.11		3.29
		5.55		5.77		6.01		4.93		5.55		5.77
Other sales		1.16		1.24		1.46		1.13		1.16		1.24
Total		6.71		7.01		7.47		6.06		6.71		7.01
TOTAL SALES		32.27		32.92		33.20		26.08		32.27		32.92

In ~~2019,~~2020, retail sales of refined products ~~(32.27~~(26.08 mmtonnes) were down by ~~0.65~~6.19 mmtonnes or by 2%19.2% from ~~2018,~~2019, mainly due to the ~~decrease of~~COVID-19 crisis which negatively affected sales ~~to oil companies and petrochemical industry~~ in Italy and ~~lower volumes marketed in the wholesalers segment~~ in the rest of Europe.

Retail sales in Italy

In ~~2019,~~2020, retail sales in Italy were ~~5.81~~4.56 mmtonnes, with a decrease compared to ~~2018 (about 100~~2019 (1.25 ktonnes from ~~2018~~2019 or down by ~~1.7%~~21.5%)~~. Retail sales~~ as result of the lockdown measures imposed mainly in the ~~premium segment increased significantly.~~second quarter, during the pandemic peak. Average gasoline and gasoil throughput ~~(1,586~~(1,206 kliters) ~~was substantially in line with 2018.~~down by 380 kliters. Eni’s retail market share of ~~2019~~2020 was ~~23.7%~~23.3%, slightly down from ~~2018 (24%~~2019 (23.6%). As of December 31, ~~2019,~~2020, Eni’s retail network in Italy consisted of ~~4,184~~4,134 service stations, lower by 3950 units from December 31, ~~2018 (4,223~~2019 (4,184 service stations), resulting from the negative balance of acquisitions/releases of lease concessions ~~(34~~(46 units), closure of low throughput stations (6(3 units)~~, partly offset by the net increase~~ and a decrease of 1 motorway concession.

Retail sales in the Rest of Europe

Retail sales in the Rest of Europe were ~~2.44~~2.05 mmtonnes, recording a ~~slight~~ reduction from ~~2018~~2019 (down by ~~1.6%~~16%) mainly due to ~~lower volumes traded~~the measures adopted against COVID-19 in ~~Germany, following~~ the ~~production unavailability at~~second quarter during the ~~Bayernoil plant and in France.~~pandemic peak.

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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 isare articulated in local marketing offices and a network of agents and concessionaires.

In ~~2019,~~2020, sales volumes on wholesale markets in Italy ~~(7.68~~(5.75 mmtonnes) ~~increased~~decreased by ~~1.9%~~25.1% from ~~2018, mainly~~2019, due to ~~higher volumes marketed~~the reduction of ~~gasoil, bitumen~~industrial activity and ~~gasoline offset by~~in particular because of lower sales of jet fuel ~~and bunkers.~~following a deep crisis of the airlines sector.

Wholesale sales in the Rest of Europe were ~~2.63~~2.40 mmtonnes, down by ~~6.7%~~8.7% from ~~2018~~2019 due to lower sold volumes in ~~Germany due to the unavailability of the Bayernoil refinery and France,~~Spain, partly offset by higher volumes in ~~Switzerland, Spain and Austria.~~Germany as a result of higher product availability due to the restart of Vohburg plant.

Supplies of feedstock to the petrochemical industry ~~(0.83~~(0.61 mmtonnes) decreased by ~~13.5%~~26.5%. Other sales in Italy and outside Italy ~~(12.40~~(10.23 mmtonnes) decreased by ~~0.34~~2.17 mmtonnes or down by ~~2.7%~~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 ~~four~~three bottling plants, 1one owned storage site and coastal storage sites located in Livorno, Naples and Ravenna.

LPG is used as heating and automotive fuel. In ~~2019,~~2020, Eni share of LPG market in Italy was ~~16.95%~~15.3%.

Outside Italy, the main market of Eni is Ecuador, with a market share of ~~37.3%~~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 ~~2019,~~2020, Eni’s share of lubricants market in Italy was ~~19.85%~~21%, in Europe 3%below 2% and on a worldwide base below 1%. Eni operates in more than 80 countries by subsidiaries, licensees and distributors.

Oxygenates

Eni’s, through its subsidiary Ecofuel (100% Eni’s share), sells approximately ~~0.9~~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 ~~70%~~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 ~~30%~~25% is purchased.

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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 ~~9.9%~~23.3% from ~~2018,~~2019, with ~~derivatives~~aromatics and olefins down by ~~10.6%~~36.4% and ~~10.2%~~25.4%, respectively. The polymers reported a decrease of ~~10.8%~~15% from ~~2018.~~2019.

Petrochemical production of ~~8,068~~8,073 ktonnes ~~decreased~~were substantially unchanged from 2019 (up by ~~1.42 mmtonnes (down by 14.9%)~~5 ktonnes) mainly due to ~~lower~~higher production of intermediates business ~~(down~~(up by ~~18.4%)~~43 ktonnes), in particular ~~aromatics~~olefins, partly offset by the reduced elastomers and ~~olefins; the polymers production of 2,250~~polyethylene productions (down by 23 ktonnes ~~decreased by 4.4% with elastomers, polyethylene~~ and ~~styrenics~~ down by ~~7.0%, 3.9% and 3.8%, respectively.~~18 ktonnes, respectively).

The main decreases in production were registered at the Priolo site (down by ~~23.3%)~~207 ktonnes), due to the ~~event occurred~~prolonged planned shutdown and at ~~the beginning of 2019 with the ramp-up finalized between April and July,~~Brindisi (down by 33 ktonnes); these reductions were offset by higher volumes at ~~the~~ Porto Marghera ~~(down~~plant (up by ~~21.9%) and Dunkerque (down by 17.1%) sites due to unplanned shutdowns.~~246 ktonnes).

Plants nominal capacity ~~is in line with~~slightly decreased from the ~~2018.~~2019. The average plant utilization rate, calculated on nominal capacity was ~~66.8%~~65%, decreasing from ~~2018 (76.2%~~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,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(ktonnes)						(ktonnes)
Intermediates		5,818		7,130		6,595		5,861		5,818		7,130
Polymers		2,250		2,353		2,360		2,212		2,250		2,353
Total production		8,068		9,483		8,955		8,073		8,068		9,483
Consumption and losses		(4,307)		(5,085)		(4,566)		(4,366)		(4,307)		(5,085)
Purchases and change in inventories		524		540		257		632		534		548
		4,285		4,938		4,646		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,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
Intermediates		1,791		2,401		1,988		1,385		1,791		2,401
Polymers		2,201		2,589		2,730		1,888		2,201		2,589
Other revenues		131		133		133		114		131		133
Total revenues		4,123		5,123		4,851		3,387		4,123		5,123

Intermediates

Intermediates revenues (€~~1,791~~1,385 million) decreased by ~~€610~~€406 million from ~~2018~~2019 (down by ~~25.4%~~22.7%) reflecting both the lower commodity prices scenario ~~influencing average intermediates prices of main products~~ and the lower product availability due to plant standstills. Sales ~~decreased~~increased by ~~18.4%,~~2.4% and by 0.8% in ~~particular for ethylene business (down by 38.0%),~~aromatics and olefins, ~~(down by 21.9%) and derivatives (down by 13.4%)~~respectively, following the ~~lower~~higher product availability.

Average prices decreased by ~~9.9%~~23.3%, in particular aromatics (down by 36.4%), olefins (down by ~~10.2%), aromatics (down by 5.4%~~25.4%) and derivatives (down by ~~10.6%~~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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~~Intermediates production (5,818 ktonnes) registered a decrease of 18.4% from 2018. Decreases were registered in aromatics (down by 19.6%), olefins (down by 18.9%) and derivatives (down by 11.3%).~~

~~Polymers~~

~~Polymers revenues (€2,201 million) decreased by € 388 million or 15.0% from 2018 due to lower volumes sold (down by 4.6%), as well as the decrease of the average prices (down by 10.8%).~~

The styrenics business ~~registered~~benefited of the ~~decrease~~increase of volumes sold ~~(down~~(up by ~~4.3%~~4%) for ~~lower~~higher product availability; decrease of sale prices (down by ~~14.7%~~16%).

Polyethylene volumes increased (up by 2%) for higher demand. Average prices decreased ~~(down~~ by ~~5.0%) due to oversupply and mounting competitive pressure from cheaper products streams from the Middle-East and the USA; decreasing of average prices (down by 7.7%)~~13.4%.

In the elastomers business, a decrease of sold volumes (down by ~~4.9%~~4.6%) was attributable to ~~NBR~~lattices (down by 8.4%), EPR (down by 6.5%), TPR (down by 4.8%), SBR rubbers (down by ~~10.3%~~4.6%)~~, thermoplastic~~ and BR rubbers (down by ~~14.8%~~3%).

Higher styrenics volumes sold (up by 4%) were mainly attributable to ABS (up by 7.8%), expandable polystyrene (up by 5.1%) and BRcompact polystyrene (4.5%), these higher volumes were partly offset by lower sales of styrene (down by ~~3.7%~~12.7%)~~; increasing~~.

Overall, the sold volumes of ~~SBR rubbers~~polyethylene business reported an increase (up by ~~1.7%~~2%) with higher sales of LLDPE and ~~lattices~~EVA (up by ~~1.0%~~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 ~~(2,250~~(2,212 ktonnes) decreased from the ~~2018~~2019 due to the lower ~~production~~productions of elastomers (down by ~~7.0%~~6.7%), polyethylene (down by ~~3.9%~~1.9%).

Capital expenditures

See “Item 5 – Liquidity and ~~styrenics~~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 ~~3.8%)~~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

64

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, as well as Eni New Energy SpA which engages in developing the business of renewable energy;~~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.

At the end of 2019, the Energy Solutions department of the Group managed by Eni New Energy, installed total capacity from renewables of 167 MW, of which 82 MW in Italy and around 86 MW abroad. By February 2020, the construction of Badamsha in Kazakhstan and Volpiano in Italy had been finalized, taking total capacity to over 190 MW. Including the Falck Renewables plants in the United States, for which a negotiation is underway, total installed capacity is around 250 MW.

Following two competitive bids, rights for the construction of a 50 MW photovoltaic plant in the Southern Kazakhstan and permits to build a 48 MW wind farm in Badamsha, were awarded to the subsidiary ArmWind LLP in Kazakhstan.

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•

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

~~Research~~A key point of our research and innovation is the integrated and transversal approach. The technology research and development team is ~~a key element in Eni’s transformation into an integrated energy company in a low-carbon future. The availability and development of cutting-edge technological skills~~indeed at the ~~service~~center of a fruitful exchange of experiences, problem solving and knowledge management in the company – providing experience, solutions, innovation and ~~sustainability and the continuous commitment to multiply the areas of application of the energy solutions identified are the common denominator of our activities.~~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 ~~2019,~~2020, Eni filed 3425 patent applications ~~(43~~(34 in ~~2018)~~2019).

In ~~2019,~~2020, Eni’s overall expenditure in R&D amounted to ~~€194~~€157 million which were almost entirely expensed as incurred (€~~197~~194 million in ~~2018~~2019 and ~~€185~~€197 million in ~~2017)~~2018).

~~Exploration & Production~~

~~Proprietary software for seismic signal processing, petroleum system modeling~~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 ~~flow assurance~~ ~~that confirms~~technological research. In 2020, about half of total R&D expenditures were dedicated to the decarbonization pathway and ~~strengthens Eni’s position~~the circular economy. In the R&D projects, the skills of at least 1500 Eni people have been used, with the ~~top~~collaboration of more than 70 Universities and Research Centers, among the most important in Italy and the rest of the ~~industry,~~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 ~~operating results~~capture technologies as well as new power generation systems with integrated capture. Hub solutions, transport networks and ~~with significant savings~~offshore injection network in depleted fields are also studied, taking advantage of the expertise acquired on ~~the cost of licenses and code maintenance.~~gas developments, through an incremental innovation approach.

~~Drilling automation~~Great expectations at the decarbonization level come from Carbon Utilization initiatives, where our research efforts are significant. In particular, CO~~. Two new tools addressing lost/non productive time~~2 reduction to methane or methanol (e-fuels) and ~~based on big data~~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 ~~were developed since 2017 to support operations. The first tool is e.NPT (Eni Non Productive Time) which analyzes and integrates multiple data sources~~lies in ~~real time in order to predict sticking events. The second tool is a new solution enabling a near real time performance analysis to identify Invisible Lost Times.~~

~~Drilling Safety Technologies: to reduce by a further order of magnitude~~ the ~~risk of blowout occurrence compared to the OGP reference. To achieve this goal, new technologies~~fact that we have been able to ~~improve well integrity both during drilling and well productive life are being developed.~~

~~Eni Subsea Hub Technology Solutions~~:develop properties that allow the product to develop, together with industry partners, technologies to significantly reduce subsea development CAPEX and OPEX by using full subsea architectures, very long step-outs and life-of-field robotics. The program starts from lessons learned from Eni’s most recent subsea

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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~~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 ~~(OIL)~~(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, 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.~~Oil Insurance Ltd. In addition, Eni uses reputable, high quality insurance companies ~~who it believes~~which are well established in the ~~marketplace.~~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 ~~$1.2~~$1.1 billion for offshore events and ~~$1.4~~$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: ~~$1,250~~$1.3 million for LNG tankers and time ~~charters;~~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

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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.

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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 ~~has~~ 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

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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 ~~must~~to transpose the directives in national ~~legislation~~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 ~~5th July 2020.~~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 ~~3rd~~ July 3, 2021. ~~According to~~

In March 2020 the UEEuropean Commission adopted a new Circular Economy Action Plan, one of the main building blocks of the European Green ~~Deal~~Deal. With measures along the entire life cycle of products, the new ~~circular~~Action Plan aims to make our economy ~~action plan is attended in March 2020, as part of~~fit for a ~~broader EU industrial strategy.~~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

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and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. ~~The Regulation was replaced two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive.~~ 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:

•

The Directive introduces licensing rules for the effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil&gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas.

•

Independent national competent authorities, responsible for the safety of installations, are in charge of verifying the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards.

•

Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities.

•

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

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

•

Outsourced equipment contracted by Eni Head Quarter;

•

Access Agreement to Subsea Capping Equipment consortium;

•

Access Agreement to Global Dispersant Stockpile consortium;

•

Eni Head Quarter proprietary equipment;

•

Rapid Cube;

•

Killing System.

As regards major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015).

The main changes in comparison to the previous Seveso Directive are:

•

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

•

expanded public information about risks resulting from Company activities;

•

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

•

stricter standards for inspections of Seveso establishments.

Eni has carried out specific activities aimed at guaranteeing the compliance of its own industrial ~~sites.~~site.

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In ~~2019,~~2020, in order to increase ~~safety’s~~safety culture in the workforce, ~~awareness-raising~~various projects and initiatives ~~continued:~~were promoted:

–

Human Factor, which mainly concerned:

•

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;

•

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

•

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.

–

Safety starts @ ~~office: realization~~home: with the continuation of ~~video clips that aim~~smart working the campaign was relaunched and enhanced to ~~raise awareness of virtuous and safe behaviors to be held in~~promote safety at home starting from the ~~office~~“Safety Golden Rules” 24 – the 10 golden rules for safety at work.

• –

~~Inside Lesson Learned Project: dissemination~~Development and ~~sharing~~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.

–

Radiation protection, preparation and implementation of a specific program in order to ensure alignment with the requirements of the ~~most significant lessons learned through video in which~~new Legislative Decree 101/2020, regarding protection from the ~~correct modus operandi is explained according~~dangers deriving from exposure to ~~Eni Safety Golden Rules;~~ionizing radiation.

• –

~~Io vivo sicuro: day~~Product safety: training on the use of ~~sharing between employees~~the tools: “Safety Data Sheet compliance evaluation” and ~~contrasts, dedicated to the creation and testing of a modular training course in the thematic areas of road safety, home safety and leisure time safety~~

•

~~Workshop on Product Safety: workshop on REACH and CLP Regulations~~“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.

~~In 2015,~~ –

Eni developed the Company Process Safety Management System (PSMS) for increasing the safety of its operations through still higher technical and management standards. ~~Starting from 2016 and in following years these standards are applied progressively in all operating activities.~~ 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 ~~2019,~~2020, the Total Recordable Injury Rate for the workforce ~~improved~~worsened by 3%5% compared to ~~2018 (0.34~~2019 (0.36 vs ~~0.35)~~0.34).

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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;

•

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

•

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

•

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;

•

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

•

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 ~~2019~~2020 Annual Report published in accordance with Italian law and practice. These reports are not incorporated by reference in this Form 20-F.

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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.

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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 ~~thirty months from the law enactment,~~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:

•

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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–

A ~~new~~ gas balancing regime, entered into force insince 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).

Management believes that these new regulation have already significantly increased and will continue increasing the level of liquidity and the competition in the wholesale natural gas market in Italy, leading to possible margin pressures.

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

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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.

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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 ~~no 157/2019~~Decree 34/2020 and ~~Law no 141/2019)~~104/2020), new measures and ~~2020 budget law, new measures~~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

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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.

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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.

•

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 45 $/barrel (recently this

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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

			2019		2018		2017				2020		2019		2018
			(€ million)								(€ million)
Sales from operations	Sales from operations			69,881		75,822		66,919	Sales from operations			43,987		69,881		75,822
Operating profit (loss)	Operating profit (loss)			6,432		9,983		8,012	Operating profit (loss)			(3,275)		6,432		9,983
Net profit (loss) attributable to Eni	Net profit (loss) attributable to Eni			148		4,126		3,374	Net profit (loss) attributable to Eni			(8,635)		148		4,126
Net cash provided by operating activities	Net cash provided by operating activities			12,392		13,647		10,117	Net cash provided by operating activities			4,822		12,392		13,647
Capital expenditures	Capital expenditures			8,376		9,119		8,681	Capital expenditures			4,644		8,376		9,119
Acquisitions	Acquisitions			3,008		244		510	Acquisitions			392		3,008		244
Disposal of assets, consolidated subsidiaries and businesses	Disposal of assets, consolidated subsidiaries and businesses			504		1,242		5,455	Disposal of assets, consolidated subsidiaries and businesses			28		504		1,242
Shareholders’ equity including non-controlling interest	Shareholders’ equity including non-controlling interest			47,900		51,073		48,079	Shareholders’ equity including non-controlling interest			37,493		47,900		51,073
Finance debt (including lease liabilities)	Finance debt (including lease liabilities)			30,166		25,865		24,707	Finance debt (including lease liabilities)			31,704		30,166		25,865
Net borrowings(1)				17,125		8,289		10,916
Net borrowings excluding lease liabilities(1)									Net borrowings excluding lease liabilities(1)			11,568		11,477		8,289
Net profit (loss) attributable to Eni basic and diluted		(€ per share)		0.04		1.15		0.94		(€ per share)		(2.42)		0.04		1.15
Dividend per share		(€ per share)		0.86		0.83		0.80		(€ per share)		0.36		0.86		0.83
Ratio of finance debt (including lease liabilities) to total shareholders’ equity	Ratio of finance debt (including lease liabilities) to total shareholders’ equity			0.63		0.51		0.51	Ratio of finance debt (including lease liabilities) to total shareholders’ equity			0.84		0.63		0.51
Ratio of net borrowings to total shareholders’ equity (leverage)(1)				0.36		0.16		0.23
Ratio of net borrowings excluding lease liabilities to total shareholders’ equity (leverage) (1)									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~~“Liquidity and capital resources – Financial ~~Conditions"~~Conditions” below.

Reported earnings

In ~~2019,~~2020, Eni reported a net ~~profit~~loss attributable to ~~Eni’s~~its shareholders ~~was €148~~of €8,635 million, ~~much~~driven by an operating loss of €3,275 million, as well as significantly lower than in 2018 when net profit of €4,126 million was reported. The reported operating profit of €6,432 million was 36% lower than in 2018, down by €3.6 billion; approximately 80% of the decline is related to the E&P segment.income from investments.

The ~~2019~~2020 results were materially and negatively affected by a challenging operating and trading environment ~~reflecting~~due to the economic crisis related to the COVID-19 pandemic, which caused a ~~slowdown~~massive reduction in ~~the global macroeconomic cycle, a deceleration in international trade triggered by the “trade dispute” between the US~~demands and China, as well as by adverse geopolitical developments that fueled uncertainty among market participants and directly affected Eni’s performance in certain areas. All of these factors have curbed demandprices for ~~energy commodities and global consumption of fuels and plastics, increasing the negative impact of~~crude oil and gas overproduction on the segment results of our Exploration&Production business, while rising competition from producers with more efficient cost structures and overcapacity pressured margins in our downstream businesses of refining and chemicals.

Against this backdrop, Eni reported a decline in oil and gas realized prices, as well as in products margins in all of its business segments. Prices and margins reductions negatively affected the reported operating profit for an estimated €2.5 billion. The main negative factor were lower gas prices in all geographies with the worst declines recorded by the European benchmark gas spot price “PSV”, which was down by 34% and negatively affected the revenues of the E&P segment relating sales volumes of equity gas. Furthermore, the result of the E&P segment was significantly and negatively affected by lower re-selling prices of volumes of gas entitlements of a Libyan partner due to a different indexation between the procurement costs, which were oil-linked, and the reselling price which was benchmarked to spot prices in Europe. Due to different trends in the indexation, this resale activity resulted in a loss to Eni, which also negatively impacted the Group tax rate.

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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 ~~2019,~~2020, non-core items included impairment losses, risk and environmental provisions, extraordinary credit losses, ~~net gains on the divestment of certain oil&gas properties,~~ 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 ~~€2,728~~€7,877 million in net profit and of ~~€2,165~~€5,173 million in operating profit, including an inventory pre-tax ~~gain~~loss of ~~€223~~€1,318 million (€~~157~~937 million post-tax).

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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 ~~DD&A charges through profit estimated at €200 million.~~allowances for doubtful accounts and other business impacts.

These negative trends were partly offset by a number of positive drivers ~~which comprised increased production volumes~~as a result of ~~hydrocarbons coupled~~management’s initiatives to cope with ~~a better production mix,~~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 ~~margin improvements~~an expansion of the customers portfolio, an increased performance achieved in the ~~wholesale gas&power~~Global Gas and LNG Portfolio business which leveraged its ~~portfolio of~~gas assets ~~long-term gas contracts, power plants and logistic capabilities~~ to benefit from market ~~volatility.~~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 ~~5%,~~€1.1 billion, partly offsetting the negativity of the trading environment and also excluding the positive accounting effect of IFRS 16 which improved the operating profit by an estimated €204 million, considering that the Company opted for not restating the comparative period.environment.

Excluding non-core items and the inventory evaluation profit, adjusted net ~~profit~~loss for ~~2019~~2020 was ~~€2.876~~€758 million, ~~37% lower than in 2018 when adjusted net profit came at €4.583 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 ~~which was~~ due to a ~~higher share of taxable income reported by~~depressed trading environment which limited the ~~Exploration & Production segment in countries subject~~Company’s ability to ~~higher-than-average~~recognize deferred tax ~~rates, a loss incurred in reselling the gas entitlements of a Libyan partner, while taxable~~assets for current losses ~~were incurred in jurisdictions with a lower-than-average statutory tax rate.~~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,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
GAAP measure of operating profit		6,432		9,983		8,012
Operating profit (GAAP measure)								(3,275)		6,432		9,983
Inventory holding (gains) and losses		(223)		96		(219)		1,318		(223)		96
Identified net (gains) losses		2,388		1,161		(1,990)		3,855		2,388		1,161
Total net non-core items in operating profit		2,165		1,257		(2,209)		5,173		2,165		1,257
Non-GAAP measure of operating profit		8,597		11,240		5,803
GAAP measure of net profit		148		4,126		3,374
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		(157)		69		(156)		937		(157)		69
Identified net (gains) losses, post tax		2,885		388		(839)		6,940		2,885		388
Total net non-core items in net profit		2,728		457		(995)		7,877		2,728		457
Non-GAAP measure of net profit		2,876		4,583		2,379
Adjusted net profit (Non-GAAP measure)								(758)		2,876		4,583

In ~~2019,~~2020, the Group’s net cash provided by operating activities was ~~€12,392~~€4,822 million, 9%€7,570 million lower than in ~~2018, despite the~~2019 or down 61%, due to a significantly deteriorated trading environment, ~~was significantly worse~~which also negatively affected the results of our equity-accounted entities and their ability to pay dividends to us, which were lower than ~~the previous year. The cash flow was supported by the collection of dividends from Eni’s joint ventures, affiliates and other minority interests~~in 2019 (€~~1,346 million), which are integrated within Eni’s strategy and development plans. The main amount was paid by the JV Vår Energi for €1,057 million.~~509 million in 2020 versus €1,346 million in 2019).

Capital expenditure and acquisitions amounted to ~~€11.384~~€5,036 million, ~~and comprised the purchase~~ of ~~a 20% interest in ADNOC Refining for a cash consideration of €2.9 billion. Capital~~which capital expenditure were ~~€8,376~~€4,644 million, ~~including~~a 45% reduction from 2019, reflecting the ~~purchase~~curtailments implemented by management following a review of ~~proved and unproved mineral interests~~the industrial plan 2020-2021 in ~~Algeria and Alaska for €0.4 billion, and were~~response to the COVID-19 pandemic crisis. These curtailments mainly ~~directed to~~affected the development of ~~hydrocarbons reserves and exploration~~

hydrocarbon reserves.

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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.

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Our ratio of indebtedness – leverage – ratio of net borrowings before IFRS 16 to total equity, ~~increased to 0.36~~which is a non-GAAP measure was 0.31 at year-end ~~2019 from 0.16~~2020 (compared to 0.24 at year-end ~~2018. Excluding the impact~~2019) and was in line with management’s expectations. The corresponding GAAP measure (ratio of ~~IFRS 16, leverage would have been 0.24.~~ 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


	2019		2018		2017		2020		2019		2018
Average price of Brent dated crude oil in U.S. dollars(1)		64.30		71.04		54.27		41.67		64.30		71.04
Average price of Brent dated crude oil in euro(2)		57.44		60.15		48.03		36.49		57.44		60.15
Average EUR/USD exchange rate(3)		1.119		1.181		1.130		1.142		1.119		1.181
Standard Eni Refining Margin (SERM)(4)		4.3		3.7		5.0		1.7		4.3		3.7
Euribor – three month euro rate % (3)		(0.36)		(0.32)		(0.33)		(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. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.~~

~~When the term margin is used in the following discussion, it refers to the~~calculations, as difference between the ~~average selling prices~~cost of a barrel of Brent crude oil and ~~reflects~~ the ~~trading environment and is,~~value of the products obtained according to ~~a certain extent, a gauge~~the standard yields of ~~industry profitability.~~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 ~~2019.~~2020.

InThe movement of the ~~first quarter~~USD vs the Euro did not affect results of operation and cash flow in 2020 ~~crude oil prices have dropped materially, hitting~~in a ~~multi-year low below 30 $/bbl driven by~~significant way; however the ~~spread~~depreciation of ~~a pandemic disease and a seemingly changed policy on~~the USD in the final part of ~~OPEC+ from supporting prices to boost production. The impact~~2020 drove a significant reduction of ~~these trends is described in~~ the ~~section “Management expectations of operations” within this item 5.~~consolidated net assets which negatively affected the Group leverage (by about 2 basis points).

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Group ~~results of operations~~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 ~~2018~~2019 Group results compared to ~~2017,~~2018, see the Annual Report on Form 20-F ~~2018,~~2019, filed to the SEC on April ~~5, 2019.~~2, 2020.

	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
Sales from operations		69,881		75,822		66,919		43,987		69,881		75,822
Other income and revenues(1)		1,160		1,116		4,058		960		1,160		1,116
Total revenues		71,041		76,938		70,977		44,947		71,041		76,938
Operating expenses		(54,302)		(59,130)		(55,412)		(36,640)		(54,302)		(59,130)
Other operating (expense) income		287		129		(32)		(766)		287		129
Depreciation, depletion and amortization		(8,106)		(6,988)		(7,483)		(7,304)		(8,106)		(6,988)
Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net		(2,188)		(866)		225		(3,183)		(2,188)		(866)
Write-off of tangible and intangible assets		(300)		(100)		(263)		(329)		(300)		(100)
OPERATING PROFIT (LOSS)		6,432		9,983		8,012		(3,275)		6,432		9,983
Finance income (expense)		(879)		(971)		(1,236)		(1,045)		(879)		(971)
Income (expense) from investments		193		1,095		68		(1,658)		193		1,095
PROFIT (LOSS) BEFORE INCOME TAXES		5,746		10,107		6,844		(5,978)		5,746		10,107
Income taxes		(5,591)		(5,970)		(3,467)		(2,650)		(5,591)		(5,970)
Net profit (loss)		155		4,137		3,377		(8,628)		155		4,137
Attributable to:
- Eni’s shareholders		148		4,126		3,374
- Non-controlling interest		7		11		3
– 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.

~~The table below sets forth certain income statement items as a percentage of sales from operations for the periods indicated.~~

Year ended December 31,
2019 2018 2017

(%)

Operating expenses 77.7 78.0 82.8
Depreciation, depletion, amortization,impairment reversals (impairment losses) of tangible and intangible and right of use assets, net 15.2 10.5 11.2
OPERATING PROFIT 9.2 13.2 12.0

Analysis of the line items of the ~~profit~~prof it and loss account

a) ~~Total revenues~~

Eni’s revenues were €71,041 million and €76,938 million for the years ended December 31, 2019 and 2018, respectively. Total revenues consist of sales from operations and other income and revenues. Eni sales from operations amounted to €69,881 million and €75,822 million for the years ended December 31, 2019 and 2018, respectively, and its other income and revenues totaled €1,160 million and €1,116 million, respectively, in these periods.

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Item 4) due to lower prices for the ~~marker~~ Brent crude oil benchmark (down by ~~9.5%)~~35.2% or 22.6 $/bbl) and lower gas benchmark prices in ~~Europe.~~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 ~~benchmark gas prices negatively affected~~equity production of hydrocarbons due to the ~~revenues earned from reselling~~effects of reduced capital expenditures to develop hydrocarbons reserves and to the ~~gas volumes entitlements of a Libyan partner in~~need to comply with the ~~European market. Finally, y-o-y comparability was negatively affected~~production quotas enacted by the ~~de-recognition of~~OPEC+ nations, as well as lower gas offtakes at our ~~former subsidiary Eni Norge at the end of 2018, following~~fields in Egypt due to a ~~business combination with the Norwegian company Point Resources to established the Vår Energi joint-venture (Eni’s share 69.6%).~~gas demand downturn.

Revenues generated by the Global Gas & ~~Power segment~~LNG Portfolio (€~~50,015~~7,051 million) decreased by ~~€5,675~~€4,728 million (or down by ~~10.2%~~40.1%). The decrease reflected lower natural gas prices ~~in Europe~~ and, ~~declining LNG prices~~to a lesser extent, reduced volumes due to a ~~weaker Asian scenario and lower volumes sold.~~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 (€~~23,334~~25,340 million) decreased by ~~€1,882~~€17,020 million (or down by ~~7.5%~~40.2%) due to lower ~~average selling~~product prices ~~of gasoline~~ and, ~~gasoil~~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 Refining & Marketing business, as well as the decline in average selling prices and lower volumes sold, mainly intermediates, in the Chemical business driven by lower demand and plant incidents and outages.energy environment.

Other income and revenues

~~2019~~2020 compared to ~~2018~~2019. Eni’s other income and revenues amounted to ~~€1,160~~€960 million in ~~2019~~2020 and mainly related to ~~the gain on the divestment of a 20% interest in the Merakes discoveries to Neptune (€145 million) and~~ the share of lease repayments debited to joint operators in Eni-led upstream projects (€~~368~~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,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
Purchases, services and other		50,874		55,622		51,548		33,551		50,874		55,622
Impairment losses (impairment reversals) of trade and other receivables, net		432		415		913		226		432		415
Payroll and related costs		2,996		3,093		2,951		2,863		2,996		3,093
Operating expenses		54,302		59,130		55,412		36,640		54,302		59,130

~~2019~~2020 compared to ~~2018~~2019. Operating expenses for ~~2019~~2020 (€~~54,302~~36,640 million) decreased by ~~€4,828~~€17,662 million ~~y-o-y,~~compared to the prior year, down by 8%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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prevailing market prices). Purchases, services and other costs included approximately €390 million relating mainly to environmental provisions and the recognition of losses on certain contractual and commercial disputes. Payroll and related costs (€2,996 million) decreased by €97 million from 2018, down by 3.1%, mainly due to the circumstance that in 2018 higher provisions for redundancy incentives were accounted relating to an early retirement program in the Eni gas e luce subsidiary.

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,
2019 2018 2017

(€ million)

Exploration & Production 7,060 6,152 6,747
Gas & Power 447 408 345
Refining & Marketing and Chemicals 485 399 360
Corporate and other activities 146 59 60
Impact of unrealized intragroup profit elimination(1)
(32) (30) (29)
Total depreciation, depletion and amortization 8,106 6,988 7,483
Impairment losses of tangible and intangible and right of use assets, net 2,544 1,292 862
Impairment of goodwill 26
Impairment reversal of tangible and intangible assets, net (382) (426) (1,087)
Write-off of tangible and intangible assets 300 100 263
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 10,594 7,954 7,521

~~(1)~~

~~This item concerned mainly intra-group sales of goods and capital, recorded at period end in the assets of the purchasing business segment.~~

	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

~~2019~~2020 compared to ~~2018~~2019. In ~~2019,~~2020, depreciation, depletion and amortization charges (€~~8,106~~7,304 million) ~~increased~~decreased by ~~€1,118~~€802 million from ~~2018, or 16%,~~2019, mainly in the Exploration & Production segment ~~(an increase~~(a decrease of ~~€908~~€787 million) mainly due to the depreciation charges of the right-of-use asset in accordance to IFRS 16, which provided a new accounting framework for operating leases without restating the comparative periods, higher charges recorded in connection with an upward revision of the present value of capitalized assets retirement costs due tocapex reductions and lower ~~interest rates,~~production, as well as ~~fields started-up and new projects ramp-up.~~lower book values of oil&gas assets following the impairment losses recorded in the interim reporting periods of 2020.

In ~~2019,~~2020, the Group recorded impairment losses at property, plant and equipment for a total amount of ~~€2,188~~€3,183 million, mainly relating to: (i) ~~impairment losses of~~ oil&gas properties ~~due~~(€1,888 million) in production or under development, driven by a downward revision to ~~downward reserves revisions and lower-than-expected performance at certain fields in Congo, Italy and~~management’s expectations for crude oil prices in the ~~USA,~~long-term, which were reduced to 60 $/barrel and the associated curtailments of ~~certain assets~~expenditures in the years 2020-2021 with the re-phasing of a number of projects, in order to ~~align the book value to fair value (for an overall amount~~preserve cash generation, as well as negative revisions of ~~€1,217 million); (ii)~~reserves. The main impairment losses were recorded byat CGUs in Italy, Algeria, Congo, the United States and Turkmenistan; (ii) the Refining & Marketing business (€1,225 million), mainly at ~~the Sannazzaro refinery, reflecting~~refineries driven by a ~~revised margin~~lowered outlook ~~both at high~~for refining margins and ~~low-complexity cycles, upward revisions~~expectations for ~~the forecast emission allowances expenses and higher capital expenses, as well as the write-down of capital expenditure relating to certain Cash Generating Units. These units were impaired~~a continuing narrowing in ~~previous reporting periods and continued to lack any profitability prospects (for an overall impact of €819 million);~~spreads between medium-sour crudes vs light-sweet crude qualities; (iii) impairment losses of Chemical assets due to ~~a lowered profitability outlook~~deteriorated margins scenario (€~~103 million in the full year)~~46 million).

Write-off charges amounted to ~~€300~~€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 ~~Australia, Kazakhstan~~Libya, the United States, Angola, Egypt, Oman, Mexico and ~~Pakistan.~~Lebanon.

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d) Operating ~~profit~~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,
2019 2018 2017

(€ million)

Exploration & Production 7,417 10,214 7,651
Gas & Power 699 629 75
Refining & Marketing and Chemicals (854) (380) 981
Corporate and other activities (710) (691) (668)
Impact of unrealized intragroup profit elimination (120) 211 (27)
Operating profit (loss) 6,432 9,983 8,012

~~The table below sets forth operating profit (loss) for each of Eni’s business segments as a percentage of each segment sales from operations (including intragroup sales) for the periods presented.~~

	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(%)						(€ million)
Exploration & Production		31.5		39.7		39.2		(610)		7,417		10,214
Gas & Power		1.4		1.1		0.1
Global Gas & LNG Portfolio								(332)		431		387
Refining & Marketing and Chemicals		(3.7)		(1.5)		4.4		(2,463)		(682)		(501)
Group		9.2		13.2		12.0
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 ~~2019,~~2020, the Exploration & Production segment reported an operating ~~profit~~loss of ~~€7,417~~€610 million, with a decrease of ~~€2,797~~€8,027 million compared to the operating profit of ~~€10,214~~€7,417 million reported in ~~2018.~~2019. The ~~decline~~decrease was driven by significantly lower ~~realized prices on equity hydrocarbons, particularly lower~~oil and natural gas prices, ~~in Europe, a loss incurred in connection with the reselling of volumes of gas entitlements of a Libyan partner,~~lower production, higher impairment losses and higher ~~amortization charges,~~write-offs of capitalized exploration well write-offs and impairment losses taken at oil&gas properties, partly offset by production growth and a better volume/mix performance reflecting higher contribution of barrels with higher-than-average profitability. The y-o-y comparison of operating profit was affected also by the following items: (i) the circumstance that the prior year result benefitted from the contribution of the former consolidated subsidiary Eni Norge (€1,278 million) which was de-recognized at the end of 2018 following the business combination with Point Resources to establish Vår Energi, an equity-accounted joint venture, fully operational since January 1, 2019; (ii) the adoption of IFRS 16, which was a positive of approximately €220 million, having Eni elected to adopt the modified retrospective approach, without restating the comparative information. A discussion on trends in production for 2019 is provided in the section “Executive summary”.expenses.

In ~~2019,~~2020, the Company’s liquids and gas realizations decreased on average by ~~8.3%~~33.6% in dollar terms, driven by a weak trading environment. Eni’s average oil realizations decreased on average by ~~9.5%~~37.5%, in line with the decrease recorded in international oil prices for the Brent market benchmark (down by ~~9.5%~~35.2% for the year). Eni’s average gas realizations decreased by 5%23.9%. The decrease in gas realization prices did not take into account the lower prices realized ~~on the~~when reselling of volumes of non-equity gas ~~entitlements~~ of athe Libyan ~~partner, which were marketed in Europe, because~~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 ~~the~~ 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 ~~2019,~~2020, non-core gains and losses included impairment charges of oil&gas assets (€~~1,217~~1,888 million), ~~environmental charges (€32 million) and~~ an allowance for doubtful accounts ~~as part of a dispute to recover credits for investments to align the recoverable amount with the expected outcome of an ongoing renegotiation~~ (€~~123~~77 million) and ~~included the gain on the assets disposal~~risk provisions (€~~145~~114 million) ~~mainly related to the disposal of the 20% interest in the Merakes discoveries to Neptune.~~.

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forward, as well as ~~a loss incurred~~force majeure at ~~the reselling of volumes of gas entitlements of a Libyan partner due~~certain fields until September 2020; (iii) higher write-off expenses relating to a mismatch between the indexation of the procurement costs vs. the reselling price; (ii) a flattening yield curve which increased the present value of the assets retirement costs capitalized as property, plant and equipment, resulting in higher amortization charges through profitunsuccessful exploration wells (€~~200~~314 million)~~; (iii) the effect of the Vår Energi deal consummated at the end of 2018 with the de-recognition of the former subsidiary Eni Norge, effective January 1, 2019.~~

. These negative trends were partly offset by ~~an improved performance driven by production growth~~optimization of operating expenses and a better volume/mix performance reflecting higher contribution of barrels with higher-than-average profitability, partly offset by bigger write-off expenses related to unsuccessful exploration wells. Management estimated that the segment internal performance increased operating profit by 7%.lower DD&A.

Operating profit included the revenues relating to certain gas volumes which were paid by the buyer without lifting the underlying volume due to the take-or-pay clause provided in a long-term supply agreement. Management has ascertained that it is highly likely that the buyer will not redeem its contractual right to lift the pre-paid volumes in future reporting periods within the contractual terms. Therefore the price paid by the buyer was recognized as revenue.

	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
Exploration & Production	(€ million)
Exploration & Production							(€ million)
GAAP operating profit (loss)		7,417		10,214		7,651		(610)		7,417		10,214
Impairment losses (impairment reversals), net		1,217		726		(158)		1,888		1,217		726
Net gains on disposal of assets		(145)		(442)		(3,269)		1		(145)		(442)
Environmental provisions		32		110		46		19		32		110
Risk provisions		(18)		360		366		114		(18)		360
Reclassification of currency derivatives and translation effects to management measure of business performance		14		(6)		(68)		13		14		(6)
Valuation allowance of disputed receivables and others				158		442		77		123		158
Reinstatement of Eni Norge amortization charges				(375)								(375)
Other		123		105		163		45				105
Total gains and charges		1,223		636		(2,478)		2,157		1,223		636
Non-GAAP operating profit (loss)		8,640		10,850		5,173		1,547		8,640		10,850

Global Gas & ~~Power~~LNG Portfolio (GGP).. This segment ~~comprises~~is engaged in the supply and sale of wholesale ~~business of~~natural gas ~~power~~by pipeline, international transport and ~~LNG,~~purchase and ~~the~~ marketing of ~~energy commodities (mainly~~LNG. It includes gas trading activities finalized to hedging and ~~power) to retail customers.~~stabilizing sale margins, as well as optimizing the gas asset portfolio. In ~~2019,~~2020, the ~~Gas & Power~~GGP segment reported an operating ~~profit~~loss of ~~€699 million, an increase of €70~~€332 million compared to ~~the~~a profit of ~~€629~~€431 million of the previous year, ~~mainly~~ due to ~~a better performance of the retail business.~~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 ~~and power~~ 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.

~~Therefore, in~~In explaining year-on-year ~~charges~~changes and in evaluating the business performance, management believes that is appropriate to ~~identify~~exclude the ~~accounting effects~~fair value of ~~fair-valued~~commodity derivatives, ~~used to hedge exposure to commodities and exchange rates,~~ which ~~lack~~lacked the formal criteria to be accounted for as hedges or ~~are~~were not eligible for the own use exemption, including the ineffective portion of cash flow ~~hedges, as well~~

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of 2020. These positive trends more than offset the ~~upsides associated with a highly-volatile environment. The improved~~lower performance ~~of the retail business was driven by effective commercial initiatives, higher extra-commodity revenues, and lower expenses. These positives were partly offset by the weaker results at our LNG business~~ due to a ~~worsening environment~~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, ~~which affected margins and volumes.~~mainly in the second quarter of 2020, that was the height of the crisis.

	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
Gas & Power	(€ million)
Global Gas & LNG Portfolio							(€ million)
GAAP operating profit (loss)		699		629		75		(332)		431		387
Impairment losses (impairment reversals), net		37		(71)		(146)		2		(5)		(73)
Environmental provisions				(1)
Provision for redundancy incentives		4		122		38		2		1		4
Fair value gains/losses on commodity derivatives		(423)		(156)		157		858		(576)		(63)
Reclassification of currency derivatives and translation effects to management measure of business performance		92		112		(171)		(183)		109		111
Estimated revenues accruals in the retail G&P						64
Revision of estimated revenues accruals in the retail G&P (difference between incurred loss vs. expected loss model)						223
Other		245		(92)		(26)		(21)		233		(88)
Total gains and charges		(45)		(86)		139		658		(238)		(109)
Non-GAAP operating profit (loss)		654		543		214		326		193		278
of which:
– Gas & LNG Marketing and Power		376		342		77
– retail business		278		201		137

Refining & Marketing and Chemicals. In ~~2019,~~2020 the Refining & Marketing and Chemicals segment reported an operating loss of ~~€854~~€2,463 million, compared to an operating loss of ~~€380~~€682 million reported in ~~2018~~2019, a deterioration of €1,781 million, driven by a challenging trading environment, ~~and significantly~~ higher impairment losses, ~~taken at property, plant and equipment. These negatives were partly offset by an increase~~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

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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 ~~lower products spreads, particularly lubricants~~optimization actions of the industrial setup and by ~~longer~~a positive performance of the bio-refineries thanks to higher processed volumes and ~~unplanned plant upset and outages. Marketing activities~~margins. The marketing business reported ansteady results, despite lower sales volumes due to improved ~~performance both in the retail and wholesale segments also leveraging on effective commercial initiatives to support~~ margins and ~~on efficiency actions.~~lower expenses.

The Chemical business reported an adjusted operating loss of ~~€268~~€229 million in ~~2019, a significant decline from 2018 when~~2020, with an improvement of 15% compared to 2019. This was achieved notwithstanding the ~~segment almost achieved breakeven. The result was~~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 ~~worsening~~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 ~~environment~~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 ~~slowdown~~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 ~~demand at~~ the ~~main end-markets, particularly~~segment performance, management generally excludes the ~~automotive sector,~~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 ~~weaker demand~~an expansion of ~~single-use plastics pressured~~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 stricter environmental regulations. Furthermore, in a shrinking global market, downward margins trends were exacerbated by rising competitive pressure from producers with lower feedstock costs (e.g., US producers using ethane-based crackers) and larger cost economies. These drivers determined unprofitable spreads betweenhigher product prices and feedstock costs mainly for polyethylene and a profitability decline at styrenics and elastomers. The operating performance was also negatively affected by the incident that occurred at the Priolo hub, which was fully operational by the end of July, and by other unplanned shutdowns.margins.

	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
Refining & Marketing and Chemicals	(€ million)
Eni gas e luce, Power & Renewables							(€ million)
GAAP operating profit (loss)		(854)		(380)		981		660		74		340
(Profit) loss on inventory		(318)		234		(213)
Environmental provisions and other costs		244		243		136
Risk provisions								10
Impairment losses (impairment reversals), net		922		193		54		1		42		2
Net gains on disposal of assets		(5)		(9)		(13)
Environmental provisions								1				(1)
Provision for redundancy incentives		8		8		(6)		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		(45)		91		52		6		6		(4)
Total gains and charges		806		760		10		(195)		296		(78)
Non-GAAP operating profit (loss)		(48)		380		991		465		370		262
– Refining & Marketing		220		390		531
– Chemicals		(268)		(10)		460
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 ~~information technology,~~

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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,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
Income (expense) on derivative financial instruments		(14)		(307)		837		351		(14)		(307)
of which – Derivatives on exchange rate		9		(329)		809
of which – Derivatives on exchange rate								391		9		(329)
– Derivatives on interest rate		(23)		22		28		(40)		(23)		22
Exchange differences, net		250		341		(905)		(460)		250		341
Finance expense on short and long-term debt		(740)		(685)		(751)
Finance expense from banks on short and long-term debt								(619)		(740)		(685)
Interest expense for lease liabilities		(378)						(347)		(378)
Interest from banks		21		18		12
Interest income due to banks								10		21		18
Net income from financial activities held for trading		127		32		(111)		31		127		32
Finance expense due to the passage of time (accretion discount)		(255)		(249)		(264)		(190)		(255)		(249)
Other finance income and expense, net		17		(173)		(127)		106		17		(173)
		(972)		(1,023)		(1,309)		(1,118)		(972)		(1,023)
Finance expense capitalized		93		52		73		73		93		52
NET FINANCE EXPENSES		(879)		(971)		(1,236)		(1,045)		(879)		(971)

In ~~2019,~~2020, net finance expenses were ~~€879~~€1,045 million, ~~a small improvement of €92~~€166 million ~~from 2018.~~higher than in 2019. This ~~reduction~~increase was due to a lower balance between gains/losses ~~at fair-valued currency derivatives, lacking the formal criteria~~due to ~~be designated as hedges under IFRS, partly offset by lower gains on~~ 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.~~risk, which lack the formal criteria to be designated as hedges under IFRS and therefore are recognized through profit and loss.

~~2019~~2020 net finance expenses include ~~€378 million~~lower finance expense relating to the ~~recognition~~accretion discount of ~~finance expenses for lease~~ liabilities ~~as required~~(up by ~~IFRS 16. Furthermore, finance~~€65 million) recognized at present value due lower discount rates.

Interest expense ~~from banks~~ on short and long-term debt ~~increased~~due to banks and other financing institutions decreased by ~~€55~~about €120 million ~~reflecting the increase~~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 ~~net borrowings.~~

~~Other net finance income and expense were a gain of €17 million, reverting a loss of €173 million accounted in 2018~~fair value driven by the ~~impairment~~depreciation of ~~operating financing receivables due by an equity-accounted entity, which engaged in~~ the ~~execution of an exploration projects that was written-off due to an unsuccessful outcome.~~US dollar and the economic downturn.

f) Net income from investments

In ~~2019~~2020 the Group reported a net ~~profit~~loss from investments of ~~€193~~€1,658 million mainly related ~~to:~~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).~~(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 ~~€247~~€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 (€~~186~~113 million, where Eni has an interest of 10.4%) and Saudi European Petrochemical Co (€4628 million, where Eni has an interest of 10%);

~~ii)~~.

a loss of €88 million recorded at equity-accounted investments, mainly in the R&M and Chemical segment (€63 million) and in the Corporate and other activities (€21 million). These share of profits at equity-accounted investments included the contribution of the upstream joint venture Vår Energi (€49 million).

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	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
Share of gains (losses) from equity-accounted investments		(88)		(68)		(267)		(1,733)		(88)		(68)
Dividends		247		231		205		150		247		231
Net gains (losses) on disposals		19		22		163				19		22
Other income (expense), net		15		910		(33)		(75)		15		910
		193		1,095		68		(1,658)		193		1,095

g) Taxes

In ~~2019,~~2020, income taxes amounted to ~~€5,591~~€2,650 million, ~~down by €379 million compared to 2018, or 6.3%. This decrease reflected lower income before taxes which was €4,361 million lower than in 2018.~~

~~Tax rate was approximately 97% compared to 59% reported in 2018, reflecting a higher share of taxable incomes reported by~~notwithstanding the ~~Exploration & Production segment in jurisdictions subject to higher-than-average tax rates, the tax effect related to~~Group incurring a loss ~~incurred in connection with~~before income taxes of €5,978 million. This was driven by a depressed pricing scenario which reduced the reselling of gas entitlements of a Libyan partner as disclosed in the “executive summary” section, while taxable losses were incurred in jurisdictions with a lower-than-average statutory tax rate. The Group ~~tax rate was also negatively impacted by~~profitability outlook driving the write-off of previously recognized deferred tax assets ~~of approximately €900 million~~(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 ~~Italian subsidiaries.~~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:

~~In 2020, we expect that~~—

the incurrence of non-deductible expenses and losses, because their tax recognition depends on the achievement of certain project milestones (such as a ~~lower crude~~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 ~~price environment will negatively affect our~~contracts, which bear tax ~~rate.~~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.

Year ended December 31,
2019 2018 2017

(€ million)

Net profit (loss) 155 4,137 3,377
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 10,480 7,657 8,720
– net gains on disposal of assets (170) (474) (3,446)
– dividends, interest, taxes and other changes 6,224 6,168 3,650
Changes in working capital related to operations 366 1,632 1,440
Dividends received by equity investments 1,346 275 291
Taxes paid (5,068) (5,226) (3,437)
Interests (paid) received (941) (522) (478)
Net cash provided by operating activities 12,392 13,647 10,117
Capital expenditures (8,376) (9,119) (8,681)
Acquisition of investments and businesses (3,008) (244) (510)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments 504 1,242 5,455
Other cash flow related to investing activities (254) 942 (373)
Net investment (divestment) of securities and financing receivables not-related to operations (*) (279) (357) 341

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.

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	Year ended December 31,						Year ended December 31,
	2019		2018		2017		2020		2019		2018
	(€ million)						(€ 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		(1,540)		320		(1,712)		3,115		(1,540)		320
Repayment of lease liabilities		(877)						(869)		(877)
Dividends paid and changes in non-controlling interests and reserves		(3,424)		(2,957)		(2,883)		(1,968)		(3,424)		(2,957)
Effect of changes in consolidation, exchange differences and cash and cash equivalents		1		18		(65)
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		(4,861)		3,492		1,689		3,419		(4,861)		3,492
Cash and cash equivalent at the beginning of the year		10,855		7,363		5,674		5,994		10,855		7,363
Cash and cash equivalent at year end		5,994		10,855		7,363		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.

Year ended December 31,
2019 2018 2017
(€ million)
Net cash provided by operating activities 12,392 13,647 10,117
Capital expenditures (8,376) (9,119) (8,681)
Acquisitions of investments and businesses (3,008) (244) (510)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments 504 1,242 5,455
Other cash flow related to capital expenditures, investments and divestments (254) 942 (373)
Repayment of lease liabilities (877)
Net borrowings(1) of acquired companies
(18)
Net borrowings(1) of divested companies
13 (499) 261
Exchange differences on net borrowings and other changes (158) (367) 474
Dividends paid, share repurchases and changes in minority interest and reserves (3,424) (2,957) (2,883)
Change in net borrowings(1) before IFRS 16 effects
(3,188) 2,627 3,860
IFRS 16 first application effect (5,759)
Repayment of lease liabilities 877
Inception of new leases for the year (766)
Change in net borrowings after IFRS 16 effects(1)
(8,836) 2,627 3,860
Net borrowings(1) at the beginning of the year
8,289 10,916 14,776
Net borrowings(1) at year end
17,125 8,289 10,916

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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.

~~Analysis of the line items of the profit and loss account~~

In ~~2019,~~2020, adjustments to reconcile the net ~~profit~~loss incurred in the year to net cash provided by operating activities mainly related to non-monetary charges, ~~and gains,~~ which primarily regarded depreciation, depletion, amortization and impairment charges and the write-off of tangible and intangible assets (€~~10,594~~10,816 million). Adjustments to net profit also included accrued income taxes (€~~5,591~~2,650 million) and interest expense (€~~1,027~~877 million), which were partly offset by amounts actually paid (€~~5,068~~2,049 million and ~~€1,029~~€875 million, respectively).

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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 ~~€8,376~~€4,644 million and ~~€9,119~~€8,376 million, respectively in ~~2019~~2020 and in ~~2018.~~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 ~~€3,008~~€392 million in ~~2019~~2020 and mainly related to the acquisition of ~~a 20% interest in ADNOC Refining in Abu Dhabi for a cash consideration of €2,896 million. The transaction is part of Eni’s strategy aimed at achieving better geographical diversification~~the control of the ~~portfolio~~Evolvere company (approximately €100 million) which engages in the business of distributed generation from renewable sources, and ~~at rebalancing along~~of minority interests in Finproject (approximately €70 million), which engages in the ~~hydrocarbons value chain. Other investments comprised a share~~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 ~~increase of €39 million at the Lotte Versalis Elastomers Co Ltd joint venture~~contributions made to certain equity-accounted entities engaged in the ~~elastomers production in South Korea and minor assets.~~execution of projects of Eni’s interest.

In ~~2019,~~2020, disposals amounted to ~~€504~~€28 million and ~~mainly~~ related to ~~the divestment of a 20% interest~~minor non-strategic assets mainly in ~~the Merakes discoveries to Neptune for €207 million, the sale of the wholly-owned subsidiary Agip Oil Ecuador BV~~E&P (€~~189~~14 million) and ~~other minor non-strategic assets.~~R&M (€11 million) businesses.

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

In ~~2019,~~2020, dividends paid and changes in non-controlling interests and reserves (€~~3,424~~1,968 million) related to ~~dividend~~the dividends paid to Eni shareholders (€~~3,018~~1,965 million of which ~~€1,542 million relating to~~comprised the 2019 ~~interim dividend and €1,476 million to the~~ final dividend for ~~fiscal year 2018)~~about €1,535 million and the ~~execution of a repurchase program~~2020 interim dividend corresponding to one-third of the ~~Eni share for €400 million.~~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 ~~€6,760~~€5,502 million as of end

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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,
2019 2018
Short-term Long-term Total Short-term Long-term Total
Finance debt (short-term and long-term debt) 5,608 18,910 24,518 5,783 20,082 25,865
Lease liabilities 889 4,759 5,648
Cash and cash equivalents (5,994)
(5,994)
(10,836)
(10,836)

Securities held for trading (6,760)
(6,760)
(6,552)
(6,552)

Non operating financing receivables (287)
(287)
(188)
(188)

Net borrowings (6,544) 23,669 17,125 (11,793) 20,082 8,289

As of December 31,
2019 2018
Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS (€ million) 47,900 51,073
Ratio of finance debt including lease liabilities to total shareholders’ equity including non-controlling interest 0.63 0.51
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest (0.27) (0.34)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) 0.36 0.16

	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, ~~2019,~~2020, total finance debt of ~~€24,518~~€26,686 million consisted of ~~€5,608~~€4,791 million of short-term debt (including the portion of long-term debt due within twelve months equal to ~~€3,156~~€1,909 million) and ~~€18,910~~€21,895 million of long-term debt. At the same date, lease liabilities were ~~€5,648~~€5,018 million (short-term portion ~~€889~~€849 million).

Total finance debt included unsecured bonds for ~~€18,779~~€19,420 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to ~~€2,611~~€1,644 million (including accrued interest and discount). Bonds issued in ~~2019~~2020 amounted to ~~€1,635~~€3,514 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro ~~(69%~~(75%), U.S. dollar ~~(30%~~(24%) and 1% in other currencies.

In ~~2019,~~2020, net borrowings including lease liabilities amounted to ~~€17,125~~€16,586 million, representing a ~~€8,836~~€539 million ~~increase~~decrease from ~~2018.~~2019. This ~~increase~~decrease was driven by the ~~initial recognition~~reduction of the IFRS 16 lease liabilities, ~~upon the adoption of IFRS16,~~ which amounted to ~~€5,759~~€5,018 million in 2020 compared to €5,648 million in 2019, down by €630 million. The ~~effect of the adoption of~~ IFRS 16 ~~on the Group net borrowings~~lease liabilities included ~~€1,976~~€1,652 million ~~of lease liabilities~~ pertaining to joint operators in Eni-led upstream unincorporated joint ventures, which ~~will~~are expected to be recovered through a partner-billing process. ~~Excluding~~

Net borrowings excluding the ~~overall impact~~lease liabilities, which is the Non-GAAP measure of ~~the adoption of IFRS 16, net borrowings~~financial condition mostly tracked by management would ~~have been at €11,477~~amount to €11,568 million, ~~increasing~~

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(€1,965 million) as well as negative foreign currency translation differences (€~~604 million;~~3,314 million) reflecting the ~~exchange rate~~depreciation of the dollar vs. the euro ~~against the US dollar recorded on~~as of December 31, 2020 vs. December 31, 2019, ~~at 1.123, compared to 1 euro = 1.146 euro US$ at December 31, 2018) which added to net equity;~~ while the ~~remuneration~~issuance of ~~Eni’s shareholders (€3,018 million),~~two hybrid bonds for approximately €3 billion and a ~~negative~~positive change in ~~the fair value of~~ the cash flow hedge reserve ~~(-€679~~(€661 million) ~~as well as the impact of the share buyback (-€400 million) detracted from~~increased net equity.

The Group Non-GAAP measure of its financial condition ~~“Leverage”~~mostly tracked by management was 0.36 at December 31, 2019, due to increased net borrowings driven by the adoption of IFRS 16 and the acquisition of a 20% interest in ADNOC Refining. The impact of the lease liability pertaining to joint operators in Eni-led upstream unincorporated joint ventures weighted on leverage for approximately 4 basis points. Excluding“leverage”, excluding the impact of IFRS 16, ~~altogether, leverage would be 0.24.~~amounting to 0.31 at year end (0.24 at year-end 2019).

Capital expenditures by segment

Exploration & Production. In ~~2019,~~2020, capital expenditures of the Exploration & Production segment amounted to ~~€6,996~~€3,472 million, mainly related to the development of oil&gas reserves (€~~5,931~~3,077 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, ~~Nigeria, Kazakhstan,~~ Indonesia, ~~Mexico,~~the United Arab Emirates, the United States, Angola, Mexico, Iraq and ~~Angola.~~Kazakhstan. Exploration expenditures (€~~586~~283 million) were directed in particular to Egypt, ~~Angola,~~Vietnam, Libya, Mexico, ~~the United Arab Emirates~~Oman and ~~Libya.~~Myanmar.

In ~~2019,~~2020, a total amount of ~~€400~~€57 million related to the purchase of proved and unproved reserves in ~~Alaska and~~ Algeria.

Global Gas & ~~Power.~~LNG Portfolio. In ~~2019,~~2020, capital ~~expenditures~~expenditure in the Global Gas & ~~Power segment~~LNG portfolio totaled ~~€230~~€11 million and ~~mainly~~ related to ~~gas marketing initiatives (€176 million) due to~~ the ~~capitalization of expenses for the acquisition of retail customers, and to the business of power generation (€42 million).~~international transport activities.

Refining & Marketing and Chemicals. In ~~2019,~~2020, capital expenditures in the Refining & Marketing and Chemicals segment amounted to ~~€933~~€771 million and regarded mainly: (i) refining activity in Italy and outside Italy (€~~683~~462 million) for the ~~rebuilding of the EST conversion plant at the Sannazzaro refinery, the upgrading of the Gela refinery into a biorefinery, increasing~~maintaining plants’ integrity and stay-in-business, as well as ~~initiatives to comply with stricter environmental and safety standards;~~HSE initiatives; (ii) marketing activity ~~mainly~~(€126 million) for regulation compliance and ~~stay in business~~stay-in-business initiatives in the ~~refined product~~ retail network in Italy and in the ~~Rest~~rest of ~~Europe (€132 million);~~Europe; and (iii) plant upgrading, efficiency and compliance to stricter environmental and safety standards in the Chemical business (€93183 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,		Three months ended March 31,		Three months ended March 31,
	2019		2020		2020		2021
Average price of Brent dated crude oil in U.S. dollars(1)		63		51		51		61
Average EUR/USD exchange rate(2)		1.136		1.100		1.100		1.200
Standard Eni Refining Margin (SERM)(3)		3.4		3.3		3.6		(0.6)
Gas at the PSV in $/mmBTU		7.1		3.7		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. Approximates~~calculations, as difference between the ~~margin~~cost of ~~Eni’s~~a barrel of Brent crude oil and the value of the products obtained according to the standard yields of the Eni refining system, ~~in consideration of material balances and refineries’ product yields.~~less expenses for industrial utilities.

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existing fields will add approximately 800 KBOE/d of new production by 2023. We have good visibility as to the ability to achieve those production targets because they relate to already-sanctioned projects, mostly of which are operated, and to incremental development phases at our existing profit centers.

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. We note that production at one of our field in Libya is currently shut down due to the situation of socio-political instability underway in the country. 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.

Our production plans and financial ~~projects~~projections are based on our Brent price scenario of 50 $/BBL in 2021 and on a gradual recovery in ~~Brent prices post 2020~~the subsequent years up to our long-term case of 7060 $/BBL in ~~2022~~2023 and going forwards (on constant monetary term ~~2022,~~2023, i.e. from ~~2023~~2024 onwards crude oil prices ~~will~~are assumed to grow in line with a projected inflationary rate). Our pricing assumptions are based on ~~forecast~~expectations of a global recovery in oil demand ~~growth~~as more economies reopen and the pandemic crisis is successfully addressed in the ~~medium term, against~~United States and Western Europe, strengthening economic activity in Asia, a slow easing of production quotas by the ~~backdrop~~producing countries of ~~a moderate pace~~the OPEC+ agreement and strict capital discipline on part of ~~expansion in the global economy. We also expect that~~ international oil companies will retain a disciplined approach to capital spending going forward, while US independent producers have shown recently the intention of shifting their focus from growth to shareholders’ returns.companies. There are some risks to this outlook, including uncertainties over the ~~strength~~effective containment of the ~~global economy, which will be significantly and negatively affected~~virus, a weaker-than-expected economic rebound in the ~~short-term by~~United States and in Europe, uncertainties over consumers’ attitude to resume travelling, the ~~spread~~possibility that the OPEC+ members could accelerate the abandonment of ~~a pandemic disease known as COVID-19,~~production curtailments and the ~~ability of OPEC+ to control global prices in light~~return on the market of the recent failed attempts in early March to implement additional production cuts seemingly triggering a discontinuation of a policy supportive of prices, as well as the role of geopolitical factors and any possible developments in the USA-China trade war and in Brexit. In the first months of 2020, after a good start to the year, crude oil prices have reversed sharply lower with the Brent crude benchmark losing more than 50% from the highs recorded early in January at 65 $/barrel, down to current values below 30 $/barrel. This sudden movement was driven by a fall in global demand for oil and rising risks of oversupplies due to spread of a pandemic disease and to the recent developments within the OPEC+, as discussed in the previous paragraph. We expect a weak trading environment throughout 2020.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~~low-price scenario. ~~First, our~~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. ~~Secondly, we~~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 of 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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~~Finally, we~~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 ~~seek opportunities for further reductions~~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 ~~development~~operations in connection with, among others, acts of war, sabotage, social unrest, clashes and ~~operating costs, for example by~~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 ~~downtime at~~geopolitical risk in our ~~facilities~~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 ~~other measures.~~Mozambique.

Global Gas & ~~Power~~LNG Portfolio

We anticipate a weak outlook in the Gas & Power segment due to structural headwinds in the industry. Gas markets across the world are currently affected by oversupplies due to an ongoing reduction in global demand for energy and rising gas supplies driven by increasing volumes of LNG from upstream projects and associated gas in the US. Furthermore, our expectations point to additional volumes of LNG coming on stream in the medium-term based on the final investment decisions of LNG projects made in 2019 for approximately 60 MTPA. Other LNG projects are expected to be sanctioned in 2020. We forecast a weak demand environment in our main reference markets, primarily in Italy and in other European countries, due to an ongoing economic downturn also driven by the impact of the COVID-19 and strong competition from renewables and trends for increasing energy efficiency. Rising LNG supplies have also increased markets liquidity and interconnections, reducing arbitrage opportunities. In our wholesale gas business, these trends are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses, whereby wholesale operators are forced to compete aggressively on pricing in order to limit the financial exposure dictated by the contracts in case of volumes off-taken below the minimum take. We also 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. In the retail business of gas and power we forecast a strong competitive environment due to lack of entry barriers and a proliferation of operators able to resell gas and power commodities to retail customers and to compete on pricing.

Against this scenario, the Company priority in its ~~Gas & Power~~GGP business is to ~~gain~~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 and to obtain operational flexibilities (volumes, points of delivery, etc)~~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 and of supporting the achievement of the final investment decisions at large gas upstream projects (for example in Mozambique). Based on this approach in 2019 we made the final investment decision for the upgrading of the Bonny LNG project in Nigeria.value-chain. We plan to ~~accelerate the growth of our~~increase contracted supplies of LNG to achieve a robust portfolio of reselling opportunities, and we are targeting 1614 million ~~tons~~tons/year of contracted volumes of LNG by ~~2025,~~2024, of which 70% deriving from our equity ~~production;~~

~~(iv)~~

To boost the profitability of the gas&power retail business, by enhancing the value of the existing customer base against the backdrop of escalating competitive pressures. This will be achieved by selectively growing our customer base, 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. Our plans targets the expansion of our customer base to 11 million of points of delivery by 2023.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 ~~there~~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 ~~2019~~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.

~~Based on the above outlined trends and industrial actions, management will seek to enhance profitability in the Company’s gas marketing business over the plan period.~~ Our profitability outlook factors in the expected outcome of ongoing and planned renegotiations of the Company long-term supply

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Refining & Marketing

The outlook of the European refining sector is challenging due to ~~structural headwinds~~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 ~~the industry pressured by~~consumption, because many economies in Europe are still in lockdown. The competitive landscape is also weak due to overcapacity, high global ~~gasoline stocks, impact~~products inventories, increasing adoption of ~~energy efficiency on fuel consumptions~~electric vehicles and ~~rising competition~~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. ~~Furthermore, fuel demand in Europe is projected to fall due to an ongoing economic slowdown now exacerbated by spread of the pandemic disease COVID-19.~~

Management expects refining margins to remain ~~on a downtrend~~subdued in the next four years and ~~beyond, reflecting progressive reduction in the oil products crack spread.~~beyond. Furthermore, our refineries are exposed to narrowing price differentials ~~shrinking~~ 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 ~~retain profitable and cash-positive operations even~~restore the profitability of its oil-based refineries in a depressed downstream oil ~~environment. Our priority is~~environment by means of capital discipline, asset optimizations to reduce the breakeven margin of Eni refineries in Europe, leveraging the full operability of our refining system, particularly with the restart of the EST high-conversion unit at the Sannazzaro refinery and the recovery of the Bayernoil plant. Other measures include optimization ofincrease plant ~~run also in view of~~reliability, maximizing yields of valuable fuels and ~~improved~~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 ~~object~~objective of improving the refinery efficiency and profitability. We are sponsoring ~~a number of~~ 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. ~~Those action are expected to significantly reduce the break-even margin of ADNOC Refining.~~ Also, a trading joint venture ~~will start~~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. ~~The~~In 2020 we achieved the full ramp-up of the Gela plant, ~~was started in the second half of 2019,~~ bringing installed capacity at our bio-refineries to 11.1 million tons per year, with profitable crack spreads between the cost of the bio feedstock and the ~~bio-productions.~~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~~phase-out palm oil as a feedstock and replace it with more ~~environmentally-sustainable~~environmentally sustainable feedstock; ~~this process of substitution is expected to~~the feedstock will be ~~completed by~~palm oil free in 2023.

~~Finally, we plan to pursue efficiency gains in logistics, to achieve energy savings and to improve plant reliability with the support of the deployment of a digital shift in our operations.~~

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 ~~for~~ electric vehicles, ~~hydrogen and~~the supply compressed natural ~~gas)~~gas and of LNG, as well as the start of the supply of hydrogene) and selling non-fuel products and services.

~~Chemical~~Chemicals business

The outlook in the ~~chemical~~chemicals business is challenging due to ~~declining consumption~~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 ~~driven by an ongoing economic slowdown in Europe, lower growth in China~~business is a very competitive market and in other emerging economies and a downturn in the automotive sector which is one of the main end-markets of the chemicals business. The situation has been made worse by the spread of the COVID-19 and the related global slowdown. Furthermore, growing public sensitivity towards the preservation of the environment and stricter regulation have negatively affected the consumption of single-use plastics and we believe that this trend will strengthen in the future. As the market contracts, the profitability of our chemicals business is expected to be negatively affected by rising competitive pressures from cheaper products stream ~~in the main commoditized segments, like polyethylene,~~ from producers in Middle East and in the USUnited States which can leverage on larger plant scale and lower feedstock costs (as in the case of ethane-feed crackers). ~~In addition,~~

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Eni gas e Luce, Power & Renewables

We expect steady profitability in the business of marketing gas and ~~(v) developing~~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 ~~green~~equity renewable energy and bio-methane, as well as by expanding the offer of new products and ~~products from recycled plastics~~services other than the commodity and ~~renewable feedstock.~~

~~Liquidity and leverage~~

~~Considering uncertain future trends~~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 ~~markets~~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 ~~global economy, the risks~~maintenance of a ~~macroeconomic downturn, oversupplies~~robust balance sheet and ~~price volatility, which~~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 ~~been exacerbated by the steep sell-off in commodity prices in the initial months of 2020~~weakened due to a ~~global economic slowdown triggered by fears~~continued contraction in demand for fuels in our reference markets (Italy and Western Europe). Finally, the appreciation of ~~pandemic disease and a failed attempt on part of OPEC + to support crude oil prices, management’s priorities~~the EUR vs the US dollar in the ~~short-term remain to maximize~~quarter will negatively affect the reported revenues and cash ~~generation from operating activities and to preserve a solid balance sheet. We believe the initiatives implemented by management in recent years intended to increase efficiency in operations,~~flows of our Exploration&Production segment.

Our financial strategy aims to reduce the ~~time-to-market~~level of ~~reserves~~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 ~~restructure~~invest on average less than €7 billion per year in the ~~mid~~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 ~~downstream~~to fund exploration activities to ensure the replacement of reserves. The businesses together with continuing management’s focus on capital discipline and the monetization of part of our exploration discoveries have improved the Company’s fundamentals and strengthened its capital structure. We believe that in 2019 we have made further progress in enhancing the competitive position of the Company and its resiliency to the market volatility through a number of actions and strategic deals aimed at rebalancing the asset portfolio along the hydrocarbons value chain and at increasing the geographic reach of our operations. Those included the expansion of the geographic presence of our Exploration & Production business in areas like the UAE, Mexico and Norway, this latter due to the acquisition of certain exploration and development E&P properties by our joint-venture Vår Energi, the growth achieved in Egypt and the acquisition of a 20% interest in the Ruwais refining complex in UAE. In future years, weenergy transition will capitalize on those initiatives and acquisitions to extract the projected returns, while at the same time we expect to continue pursuing financial discipline and sustainable growth to drive profitable production increases and an improved sales volumes mix with the addition of more valuable barrels, reserve replacement and margin expansion at our mid and downstream businesses driven by synergies from integration, the repositioning of the refining and petrochemicals businesses and a growing customer base in the gas retail operations, as well as to reduce climate-related risks by developing our planned initiatives designed to expand the renewable generation capacity, to promote the circular economy and make our operations less carbon-emitting.

~~The initiatives planned~~attract €9 billion in the next four years, ~~are~~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 ~~reach~~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 ~~low price~~variable dividend will be paid to shareholders as a portion of the ~~Brent crude oil at which the Company will be able to fund through~~incremental cash flow from operations ~~both~~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 ~~dividend. Specifically, based~~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 ~~these actions~~stream, operating over 70% of the new production. These are mainly in Angola, Indonesia, Mexico, Mozambique, Norway and ~~on the planned underlying growth in cash generation, we expect net cash provided by operating activities to fund the planned yearly amount~~United Arab Emirates. In terms of ~~organic capital expenditure and the full dividend at~~future production mix, around ~~45 $/BBL for the Brent crude,~~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 ~~period.~~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;

~~During~~(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 ~~spite~~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 sharp contraction in the operating cash flow due to lower oil prices, the Company has managed to hold its key ratio of net borrowings to equity – leverage – below a preset ceiling through a combination of cost cuts, asset disposals, capital expenditure curtailments and working capital optimizations. At the end of 2019, our leverage stood at 0.24 before the impact of IFRS 16 (0.36 including the effect of IFRS 16). The Company intends to retain a strong control on the evolution of leverage going forward.

~~Our cash flows from operating activities are~~business lines exposed to the volatility of the oil ~~price environment. Currently, based~~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 ~~properties,~~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 ~~assumptions~~forecast of 50 $/BBL for ~~2020.~~2021. Currently, oil prices are ~~on a downtrend~~in an uptrend due to the recent developments occurred until now in ~~2020~~2021 described inabove, with the ~~above paragraph~~average

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~~“Impact~~Brent price for the first quarter of ~~COVID-19 and other current trends~~2021 at above 60 $/bbl. This trend will be partly offset by the significant contraction recorded by the refining margin in the ~~oil market”.~~first quarter 2021, with our benchmark SERM in negative territory. We ~~retain some levels~~are currently estimating a change of ~~financial flexibility that we may use in case oil prices should take another leg down~~cash flow from our refining business of approximately €160 million per each one-dollar change in the ~~cycle in~~SERM compared to the ~~remainder~~assumption for 2021 of ~~the year or in subsequent years. In addition, we retain cash reserves and committed and uncommitted borrowing facilities.~~$3.8 per barrel.

For planning purposes, management assumed a EUR/USD exchange rate in the range of ~~1.11~~1.19 – ~~1.21~~1.23 U.S. dollars per euro in the ~~2020-2023~~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 ~~2020~~of 2021 the EUR/USD exchange rate was approximately ~~1.1~~1.2 and ~~was substantially unchanged year-on-year (it was 1 EUR=1.135 USD in~~has appreciated significantly, year-on-year; this trend will reduce the ~~first quarter~~cash flow of ~~2019).~~ the Eni’s E&P segment compared to the previous year.

See “Item 3 – Risk factors”.

~~Remuneration policy~~

Management is committed to a progressive remuneration policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. Dividends will be driven by the results that ultimately will be achieved in implementing our strategy and by our ability to achieve the targeted Brent prices at which the Company’s net cash provided from operating activities is able to fund planned capital expenditures and dividend payments. Management is forecasting to increase the dividend expected for fiscal year 2020 to 0.89 €/ share compared to 0.86 €/share for fiscal year 2019, up by 3.5%. The Company had previously announced and launched a share repurchase program as a flexible tool to return shareholders the cash in excess of that committed to achieve the targeted range of leverage, provided that Brent crude oil prices do not fall below a preset level. In 2019, we spent €400 million on share repurchases. Considering the current trends in the oil market, management has resolved to suspend the share repurchase plan for 2020.

~~The program will be reconsidered when the Brent price for the referenced year, which is the benchmark for decisions relating to the buyback plan activation, is at least equal to 60$/barrel.~~

~~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.~~

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, ~~the impact of COVID-19 on global hydrocarbon demand, the role of OPEC+ at supporting crude oil prices,~~ political instability in Libya and other countries, crude oil and natural gas prices; ~~global~~ demand for oil~~&gas; trends in natural gas demand~~&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 ~~designed to tackle the risks of climate change~~and climates in countries and regions where Eni ~~operates or on a global scale;~~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.

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Working capital

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

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay ~~amount~~amounts due. For a description of how the Company manages the credit risk see “Item 18 – Note 27 of the Notes on Consolidated Financial Statements”.

For more information about ~~credit losses in 2019 and~~ the allowance for doubtful accounts calculated in accordance with the expected credit loss model see “Item 18 – Note 7 of the Notes on Consolidated Financial Statements”.

Market risk

In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see “Item 18 – Note 27 of the Notes on Consolidated Financial Statements”.

Research and development

For a description of Eni’s research and development operations in ~~2019,~~2020, see “Item 4 – Research and development”.

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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, ~~2019:~~2020:

Name Position Year elected or appointed Age
Emma Marcegaglia Chairman 2014 54
Claudio Descalzi CEO 2014 64
Andrea Gemma Director 2014 46
Pietro A. Guindani Director 2014 61
Karina A. Litvack Director 2014 57
Alessandro Lorenzi Director 2011 71
Diva Moriani Director 2014 51
Fabrizio Pagani Director 2014 52
Domenico Livio Trombone Director 2017 59

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 ~~April~~May 13, ~~2017~~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, ~~2019.~~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.

~~Emma Marcegaglia,~~Lucia Calvosa, Claudio Descalzi, ~~Andrea Gemma~~1~~, Diva Moriani, Fabrizio Pagani~~Ada Lucia De Cesaris, Filippo Giansante, Emanuele Piccinno, and ~~Domenico Livio Trombone~~Nathalie Tocci were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina A. Litvack and ~~Alessandro Lorenzi~~Raphael Louis L. Vermeir were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed ~~Emma Marcegaglia~~Lucia Calvosa as the Chairman of the Board of Directors and, on ~~April 13, 2017,~~May 14, 2020, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.

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

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

~~Emma Marcegaglia~~Lucia Calvosa was born in ~~Mantua in 1965~~Rome and has been Chairman of ~~Eni~~Eni’s Board since May ~~2014.~~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 since November 2014. She is also Chairman and CEO of Marcegaglia Holding SpA and Deputy Chairman and CEO of the subsidiary companies operating in the processing of steel. She is also Chairman and CEO of Marcegaglia Investments Srl, the holding company of the diversified activities of the group.(FEEM). She is a member of the ~~Board~~Italian Corporate Governance Committee.

Experience

She was Chairman of ~~Directors~~Cassa di Risparmio of ~~Bracco~~San Miniato SpA and ~~Gabetti Property Solutions SpA. From 1994 to 1996~~in that capacity, she was ~~National Deputy President of Young Entrepreneurs of Confindustria, from 1997 to 2000 she was President~~also member of the ~~European Confederation~~Banking Companies committee and Director of the ~~Young Entrepreneurs (YES), from 1996 to 2000 President of Young~~ Italian ~~Entrepreneurs of Confindustria~~Banking Association (ABI). She served as independent director and from 2000 to 2002 she was Vice President of Confindustria for Europe. From May 2004 to May 2008 she was Confindustria Vice President for infrastructures, energy, transport and environment and Italian RepresentativeChairman of the ~~top High Level Group for energy, competitiveness~~Control and ~~environment set up by the European Commission. From May 2008 to May 2012 she was President~~Risk Committee of ~~Confindustria. From July 2013 to July 2018 she was President~~Telecom Italia SpA. She also served as independent director of ~~Businesseurope.~~SEIF SpA and Banca Monte dei Paschi di Siena SpA. She was a member of the ~~Management Board~~Commission for the National Scientific Qualification for first and second-level university professors in sector 12/ b1 – Commercial Law. She was a member of ~~Banco Popolare~~the Bankruptcy Procedures and ~~Director of Finecobank SpA and Italcementi SpA. She held the position of~~

1

Temporarily interdicted from the office of Director for facts relating to another issuer with Consob Resolution of June 26, 2019. The “Corte d’Appello” of Rome suspended the provision with effect from November 4, 2019.

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~~Chairman~~Corporate Crisis Commission of the ~~Aretè Onlus Foundation. From July 2010 to June 2019 she was President~~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 ~~Luiss Guido Carli.~~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 ~~graduated~~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 ~~Business Administration at~~ the ~~Bocconi University~~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 ~~Milan~~highly complex and ~~attended a Master in Business Administration at New York University.~~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~~ & 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.

~~Andrea Gemma~~Ada Lucia De Cesaris was born in ~~Rome~~Milan in ~~1973~~1959 and has been a Director of Eni since May ~~2014. He~~2020.

She is ~~Professor~~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 ~~Private Law at The Third University~~environmental critical issues.

In 1986 she contributed to research on the problems of ~~Rome and was visiting professor at European Universities and at Villanova University. He is~~energy governance, within the “Finalised Energy Programme”. Since 2000 she has been a member of the ~~Strategic~~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 ~~American~~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 ~~Rome.~~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 ~~Appeal Court Lawyer.~~ currently General Manager – Head of the Public Heritage Development Department of the Italian Treasury.

He is ~~President~~a member of the Board of ~~Statutory Auditors~~Directors of ~~PS Reti~~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 ~~Sirti SpA.~~ SACE SpA (2004-2007).

He ~~is also Official Receiver~~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 ~~Valtur SpA, Liquidator~~the Administrative Council for Italy at the Council of ~~Novit Assicurazioni SpA~~Europe Development Bank (2016-2017). Furthermore, he was Executive Director for Italy of the European Bank for Reconstruction and ~~Sequoia Partecipazioni SpA.~~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 ~~Advisory~~ Board ~~in Bridges Ventures LLC,~~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 and of the Board of Governors of the CFA Institute.~~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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~~Alessandro Lorenzi~~ was born in Turin in 1948 and has been Director of Eni since May 2011. He is Director and Chairman of the Internal Control Committee of Ersel SIM SpA and of Banca Albertini SpA. He began his career at SAIAG SpA in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined GFT Group where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Operating Officer and was subsequently Director of Ersel SIM SpA until June 2000. In 2000 he became Executive Officer of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of Coin Group and in 2006 he became Chief Corporate Officer at Lavazza SpA, becoming Board member from 2008 to June 2011. From July 2011 to September 2017 he was Chairman of Società Metropolitana Acque Torino SpA. From June 2016 to April 2019 he was Director of Mutti SpA.

~~Diva Moriani~~ was born in Arezzo in 1968 and has been a Director in Eni since May 2014. She is currently Executive Vice Chairman of Intek Group SpA, Vice Chairman of KME AG, a German holding company of KME Group, Director of KME Srl, Member of the Supervisory Board of KME Germany GmbH and Director of Assicurazioni Generali SpA, Moncler SpA, Dynamo Academy, Dynamo Foundation and Associazione Dynamo. From 2007 to ~~2012~~2009 she was ~~CEO of I2 Capital Partners, a private equity fund sponsored by Intek Group SpA, with~~ an ~~investment strategy focused on “Special Situations” and from 2014 to 2017 CEO of KME AG. She graduated in Economics~~Associate Fellow for EU foreign policy at the ~~University of Florence.~~

~~Fabrizio Pagani~~Centre for European Policy Studies in Brussels. From 2009 to 2010 she was ~~born in Pisa in 1967~~Senior Fellow for Turkey’s relations with the United States, the European Union and ~~has been a Director in Eni since May 2014. He is Head of Economics and Capital Market Strategy of Muzinich & Co. and Board member of Save SpA, Banca Finint SpA. From 2014 to 2018 he has been Head of~~ the ~~Office of the Minister of Economy and Finance. He was Deputy Director of the International Training Programme for Conflict Management~~Middle East at the ~~High School S. Anna~~Transatlantic Academy in ~~Pisa from 1995~~Washington. From 2012 to 1998, Professor of International Law in the Faculty of Political Science at the University of Pisa from 1993 to 2001, Deputy Chief of the Legislative Office at the Department of European Affairs from 1998 to 1999 and Counsellor for International Affairs in the Ministry of Industry and Foreign Trade from 1999 to 2001. He2014 she was ~~Senior Advisor at the OECD from 2002 to 2006, Head of the Office of the State Undersecretary, within the Prime Minister Office from 2006 to 2008, board~~ member of SACE SpA from 2007 to 2008, Political Counsellor of the OECD General Secretary from 2009 to 2011, Director of the G8/G20 Office at the OECD from 2011 to 2013 and Senior Economic Counsellor to the Prime Minister and G20 Sherpa from 2013 to 2014. He was a NATO Fellow and was a visiting scholar at Columbia University, New York. He graduated in International Studies at the Scuola Superiore Sant’Anna, Pisa, and has a Master degree from the European University Institute, Florence.

~~Domenico Livio Trombone~~ was born in Potenza in 1960 and has been Director of Eni since April 2017. He is a certified chartered accountant and a certified public auditor. He is partner of Studio Trombone Dottori Commercialisti e Associati. He is currently Chairman of the Board of Directors of ~~Consorzio Cooperative Costruzioni-CCC,~~the University of ~~Focus Investments SpA,~~Trento. In 2014 she was Councillor for international strategies of ~~Società Gestione Crediti Delta SpA and~~the Minister of Prelios Credit Servicing SpA. He is, among the others, Director of International World Group Srl. Furthermore, he is Chief Executive Officer of Atrikè SpA and Sole Director of FINCCC SpA and of Focus Investment International Srl. He is also ChairmanForeign Affairs, Federica Mogherini (June-November 2014).

From 2013 to 2020 she was member of the Board of ~~Statutory Auditors~~Directors of ~~Coop Alleanza 3.0 Sc, Cooperativa Immobiliare Modenese Soc. Coop., H2I SpA~~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 ~~Tenute del Cerro SpA.~~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 ~~standing Statutory Auditor, among~~currently an independent advisor for the ~~others, of: Arca Assicurazioni SpA, Arca Vita SpA, Cooperare SpA, Il Ponte SpA, Unipol Finance Srl, Unipol Investment SpA, UnipolPart I SpA~~mining and ~~Unisalute SpA.~~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 ~~Liquidator~~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 ~~Italcarni Sc~~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 ~~Open.Co S.c. He is technical consultant~~2011 was appointed as president of operations in ~~legal proceedings, coadjutor in bankruptcy proceedings, liquidator, trustee in bankruptcy~~Nigeria.

Subsequently and ~~judicial commissioner. Over the years he held positions in banks, in asset management and insurance companies. More in detail, he~~until 2015, Vermeir was ~~standing Statutory Auditor in Carimonte Holding SpA, Unicredit Servizi Informativi SpA, Immobiliare Nettuno Srl, Gespro SpA and in PLT Energia SpA. From April 2006 to March 2007 he~~Vice President of Government Affairs International for ConocoPhillips.

Raphael Louis L. Vermeir was ~~Director of Aurora Assicurazioni SpA. From October 2007 until the merger~~a member of the ~~Company in FonSai SpA, he~~Board of Directors of Oil Spill Response Ltd and until 2011 was Chairman of the ~~Board~~International Association of ~~Statutory Auditors~~Oil and Gas Producers for four years in ~~Unipol Assicurazioni SpA. Until December 2008~~a row.

A Belgian national, he ~~was Director~~graduated in ~~Banca Popolare del Materano SpA~~Electrical and ~~BNT Consulting~~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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Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause.

Senior Managers

~~Luca Bertelli~~ was born in Sesto Fiorentino in 1958. He graduated with honours in geology in 1983 from the University of Florence. In 1984 he joined Eni’s geophysics division, working first as a researcher in the development of 3D seismic prospecting technology and subsequently as a manager of 3D seismic prospecting programmes, specialising in seismic-stratigraphy. In 1994 he was appointed manager of seismic-stratigraphy applications and in 1999 he increased the technical-managerial scope of his activities becoming manager of geological and geophysical services in Eni.

At the end of 2001, his career took a new international turn holding positions of increasing managerial complexity over a period of eight years, starting in Norway where he was Technical Director and Deputy Managing Director at Norsk Agip in Norway. In 2003 he was appointed Managing Director of Eni Indonesia and in 2006 he moved to Egypt as General Manager and Managing Director, a position he also held at Eni Angola in 2007. In 2009 he returned to Eni’s headquarters as Senior Vice Chairman of Global Exploration. He was appointed Executive Vice President of Exploration and Unconventional at the beginning of 2010. Since July 1, 2014, he has been Eni’s Chief Exploration Officer.

~~Stefano Maione~~ was born in Avellino in1963. He has a degree in Civil Engineering from the University of Bologna. Stefano Maione was hired by Agip S.p.A. in 1991 as a Field Engineer, gaining significant experience in dynamic modelling of oil fields and contributing to studies of fields in Egypt and China. In 1994 he transferred to Agip Récherches Congo S.A., again as a Field Engineer, where he developed his skills and experience in oil fields and eventually reached the position of Head of Field Operations. Returning to headquarters in early 1999, he occupied increasingly important roles in technical services, finally becoming District Head of Production for Italy. From 2003 to 2006 he gained significant experience as a Development Project Manager in Egypt, Libya, Iran and Italy. In 2007, he was elected as a member of the Management Committee that runs Mellitah Gas B.V. Libyan Branch, 50% of which is controlled by Eni and 50% by the National Oil Corporation (NOC). In January 2009, he was appointed Managing Director of Eni Iran B.V. and in 2010 returned to Libya as Managing Director of Eni North Africa B.V. Returning to headquarters again in January 2012, he was appointed Senior Vice President of Development Projects and Deputy Chairman of the Development Department. He was put in charge of the Mozambique Programme in 2013 after Eni discovered super-giant gas fields in the country, becoming Executive Vice President for it in 2015. He was appointed Chief Development, Operations & Technology Officer on July 1, 2019.

~~Claudio Granata~~ was born in Rome in 1960. Graduating with a degree in economics, he joined the Eni group in 1983. 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.

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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 ~~lawyer~~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 ~~few years~~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 ~~a law firm in Milan. He joined Eni in 1997 in the Legal Department of Agip SpA, mainly following international legal projects until 2001 when~~2003 he took on the ~~responsibility~~role of ~~International Legal Assistance~~Business HR for Eni Corporate, ensuring support for departments in the management and development of ~~Exploration~~Eni Corporate’s managerial resources during a period of profound change (2002-2004), which was characterised by the mergers of Snam and ~~Production Division.~~AgipPetroli and the restructuring of staff organisation. In ~~2005~~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 ~~Legal~~Human Resources Director of the ~~Gas &Power~~E&P Division, ~~further diversifying his business knowledge. In 2007,~~where he ~~is back~~oversaw the planning, management, development and compensation processes for human resources and organization activities. He also collaborated with the top management in the ~~Exploration & Production Division as Legal Director. In 2008, following~~reorganisation of macro processes for the ~~centralization~~division and promoted change management initiatives. He became a board member of Eni International Resources Ltd in 2006 and was Chairman of the ~~Eni’s legal function into one Legal Department,~~board of Eni International Resources Ltd from 2012 to 2013. From 2012 to March 2015 he ~~took on responsibility for the legal assistance to the company’s activities outside Europe.~~ was a board member of Eni UK Ltd.

In 2013 he was appointed Executive Vice President ~~International Business Legal Area~~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 ~~2015, he~~2000, she worked on Eni operated assets in Scotland (North Sea).

In 2004, after moving to the Engineering and Projects Department, she became ~~Executive~~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 ~~International~~for West Africa Projects Monitoring and ~~Finance Legal Affairs~~Technical Coordination and later in Eni Congo as Development Projects Director, where she also became the President of ~~Eni, with a strong exposure~~Enrico Mattei School in Pointe Noire.

In 2017, she was called to ~~international matters,~~

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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. ~~Since January 1, 2019, he has been Legal Affairs Senior Executive Vice President.~~

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. ~~Since~~

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 ~~he has been~~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 ~~Executive~~ 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 ~~Affairs~~Publishing, a position held until April 2016 when she took on the role of Senior Vice President Media Relations and Social Networks.

7

He was the Board Secretary of Eni and Corporate Governance Counsel and Company Secretary and a Board Member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel and Company Secretary. Since May 2018, he has been Coordinator of the Corporate Governance Forum of Company Secretaries.BV until December 2020.

~~Marco Bardazzi~~ was born in Prato in 1967. He is a professional journalist working in the media world for 28 years before joining Eni in 2015. He has gained extensive experience on foreign policy and digital communications, particularly in Europe and America. Between 2009 and 2015 he was Managing Editor and Digital Editor at “La Stampa”. He was a key member of the team that worked on the transformation of a traditional newspaper to an integrated digital news organization, creating an innovative “concentric circles” multiplatform newsroom. He was one of the co-founders of “Europa” a partnership between La Stampa, Le Monde, El País, The Guardian, Gazeta Wyborcza and Suddeutsche Zeitung. Before joining “La Stampa”, he was U.S. correspondent for the Italian news agency ANSA between 2000 and 2009, covering every aspect of American life for the Italian media. Among other things, he covered the Bush-Gore electoral race for the White House in 2000, the first international Al Qaeda trial in Manhattan, the September 11 attack on America, the wars in Afghanistan, and Iraq and the 2004 and 2008 presidential campaigns. He has visited and reported on the Guantanamo detention camp at the U.S. Navy Guantanamo Bay base in Cuba. He won the Saint-Vincent Award for Journalism for a series of reports on the death penalty in the USA. He covered the 2008 financial crisis, and he reported extensively on the American digital, energy and automobile industries.

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He holds an Associate of Arts degree in History from American Public University. His latest book is “L’Ultima Notizia” (with Massimo Gaggi, Rizzoli 2010), an essay on digital transformation in the media business. He is an external lecturer in the Masters in Journalism in ALMED-Università Cattolica del Sacro Cuore, Milan. He is a Visiting Fellow at the University of Oxford. In ~~2017 he was appointed as a Director of Agi SpA and Eni Gas e Luce. Since February 2015, he has been External Communication Executive Vice President.~~

~~Luca Cosentino~~ was born in Venice in 1961. He graduated cum laude with a degree in geology in 1985 from the University of Padua and joined Eni in 1986. He spent the first years of his professional life in the Reservoir Department, within the reservoir modeling group. Between 1992 and 1996, he worked in different operational positions in Italy and abroad in the reservoir sector. From 1996 to 2003, he worked as Project Manager with IFP (Institut Français du Petrol, France), in Venezuela and in the Persian Gulf. In this period, he also taught at the IFP School and published several technical papers, including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to 2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From 2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed2018 she became Senior Vice President ~~Non Operated Business Performance~~Global Media Relations and ~~Stranded Resources Valorization. Since November~~Crisis Communications.

From July 1, ~~2015, he~~2020 she was Eni’s Director Media Relation reporting directly to the CEO until she assumed the current role. She has also been ~~Executive Vice President Energy Solutions.~~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. ~~He was appointed Executive Vice President of International Affairs on April 14, 2017.~~

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 ~~graduate~~member of the Board of the European Chief Compliance and Integrity Officers Forum (ECCIOF). After graduating in Law from the University of Milan, ~~and is registered to practice law on the special list of the Ordine degli Avvocati (the Italian Bar Association) in Rome. He~~he first joined Eni in 1991 in the legal department of the then Agip SpA, ~~initially involved in disputes and~~ providing legal assistance, ~~to the~~initially, in commercial litigation and procurement area, ~~before going on to delivering legal support for~~and, subsequently, in a wide range of national and international projects in the Exploration & Production sector. In 2000, ~~in the context of~~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 ~~creation~~establishment and ~~launch~~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 ~~was engaged in providing legal support in the regulatory and antirust areas, gradually extending his responsibilities and~~takes on positions of increasing responsibility, becoming, in 2009, head of ~~Legal Assistance for the business and Antitrust issues in Italy, as well as council for~~ legal assistance for ~~the activities~~Italian Business and Antitrust and in 2015, head of ~~the Refining & Marketing sector.~~Legal and Regulatory Compliance. He was also

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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 ~~he reports directly to the Chief Executive Officer~~ in his role as Executive Vice President Integrated Risk ~~Management.~~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, ~~2019,~~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 ~~2019~~2020 period, filled said roles, even if only for a fraction of the year), was ~~€1,427~~€1,332 thousand.

Name

(€ thousand)

Descalzi Claudio

Chief Executive Officer

~~371~~376

Senior managers(a)

~~1,056~~956

TOTAL

~~1,427~~1,332

(a)

No. 2022 managers.

Board practices39

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 ~~complies~~complied with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) approved by Italian Corporate Governance Committee, ~~(hereinafter “Corporate Governance Code” or “Code”),~~ lastly amended on July ~~2018.~~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 ~~related~~relevant table above.

3

~~The information contained in this chapter is updated to December 31, 2019 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 ~~Corporate Governance~~ 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.

~~Finally,~~On the same date (May 14, 2020), the Board of Directors ~~entrusted~~appointed the Secretary of the Board ~~Secretary~~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 ~~lends~~provides assistance and independent (from the management) legal advice to the Board and the ~~Directors and periodically presents to the Board of Directors a report on the functioning of Eni’s Corporate Governance system.~~Directors.

On ~~April 13, 2017,~~May 14, 2020, the Board reserved to itself the strategic, operational and organizational powers briefly described ~~below:~~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.~~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 ~~respect~~regard to the ~~characteristics~~nature of the ~~Company~~business and its risk profile, as well as the system’s effectiveness;

•

approves at least annually the Audit Plan drawn up by the ~~Senior Executive Vice President~~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 ~~statement on~~additional report, together with any comments of the ~~key issues that arose during the statutory audit;~~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;

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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 Board410, 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 ~~strategic, economic, financial or asset~~ impact on the ~~Company;~~Company’s strategy, performance or financial position;

•

appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the ~~Senior Executive Vice President~~Director of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of ~~a manager~~people of the relevant structures responsible for institutional investors and shareholder relations;

•

examines and approves the ~~Remuneration~~ Report on remuneration policy and ~~in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities~~remuneration paid to be presented to the Shareholders’ Meeting. It also defines the ~~criteria for remunerating~~remuneration of Directors with delegated powers and with special duties, establishes the ~~senior executives~~objectives – and verifies their achievement – applicable to the variable remuneration of ~~the Company~~Directors with delegated powers and ~~of the Group~~incentive plans and ~~takes steps to implement~~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 ~~retain representative powers for~~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 ~~April 13, 2017 and, after an investigation by the Nomination Committee, lastly at its meeting of February 27,~~May 14, 2020, the Board of Directors determined that Chairman ~~Marcegaglia~~Calvosa and Directors ~~Gemma,~~De Cesaris, Guindani, Litvack, ~~Lorenzi, Moriani~~Piccinno, Tocci and ~~Trombone~~Vermeir satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors ~~Gemma,~~De Cesaris, Guindani, Litvack, ~~Lorenzi, Moriani~~Tocci, and ~~Trombone~~Vermeir have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance ~~Code.~~Code 2018. Chairman ~~Marcegaglia,~~Calvosa, in compliance with the Corporate Governance Code 2018, could not be deemed independent as she is a significant representative of the Company.511

At the last assessment carried out on May 2020, the Board of Directors also evaluated that the ~~commercial relationships~~relationships: (i) between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative ~~and~~pursuant to the Corporate Governance Code 2018; (ii) between Eni and ~~companies~~a law firm whose partner is a relative of ~~the KME Group, companies subject to significant influence, also indirectly, by~~ Director ~~Moriani,~~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,~~Company.

The Board of Statutory Auditors verified the proper application of criteria and ~~taking into account that – due to~~procedures adopted by the ~~nature~~Board of Directors in assessing the ~~companies mentioned above – transactions between these~~independence of its members.

410

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.

511

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)~~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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companies and Eni were subject to related parties’ transactions regulation and reported to the Company’s body. The Board of Directors also confirmed the independence of Director Lorenzi, who the next May 5, 2020 will complete the ninth year of office as Director, taking into account that his office as Director will expire on May 13, 2020.

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

~~The~~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 ~~Corporate Governance Code.~~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 ~~Corporate Governance Code.~~Code 2018.

The Committees recommended by the ~~Corporate Governance~~ 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 ~~him,~~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 remuneration612.

The Board Secretary and Corporate Governance Counsel coordinates the secretaries of the Board Committees, receiving atfor this ~~end~~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 ~~April 13, 2017.~~May 14, 2020.

Remuneration Committee

Members: ~~Andrea Gemma~~Nathalie Tocci (Chairman), ~~Pietro~~Karina A. ~~Guindani, Alessandro Lorenzi, Diva Moriani.~~Litvack, Raphael Louis L.Vermeir.

6

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 remuneration are being discussed, unless are deemed proposals on all the members of the Committees established within the Board of Directors.”

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a)

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;

b)

periodically evaluates the adequacy, overall consistency and effective implementation of the Policy, formulating proposals, as appropriate, for approval by the Board of Directors;

c)

presents proposals for the remuneration of the Chairman and the Chief Executive Officer, including the various components of compensation and ~~non monetary~~ benefits;

d)

presents proposals for the remuneration of Board Committee members;

e)

having examined the Chief Executive Officer’s ~~indication,~~input, proposes general criteria for the compensation of Managers with strategic responsibilities, the annual and Long-Term incentive plans, including equity-based ~~ones,~~plans, sets performance objectives and assesses performance against them, ~~in connection with the determination of~~thereby determining the variable ~~portion of the remuneration for~~awards due to Executive Directors ~~with delegated powers and with~~pursuant to the implementation of the approved incentive plans;

f)

monitors execution of decisions taken by the Board;

g)

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. In carrying out its duties, the Committee~~plan and may access the information and Company ~~functions~~managers as necessary to perform its duties, and ~~can~~to avail itself of independent external advisors ~~who are not in positions that might compromise their independence of judgement,~~ within the terms and budget limits ~~established~~set by the Board of Directors.

The Committee also reports on its procedures at the ~~procedures it adopts in performing its functions to the~~Annual Shareholders’ Meeting called to approve the financial statements through its ~~Chairman~~Chairwoman or ~~another Committee~~other duly designated member, ~~designated by the Chairman, in accordance with the recommendations in the Corporate Governance Code and~~ with the goal of establishing and appropriate channel for dialogue with shareholders and investors.

During ~~2019,~~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, ~~whit constant participation of~~while the Chairman of the Board of Statutory ~~Auditors.~~Auditors attended all meetings. At the invitation of the Chairman of the Committee, managers of the Company ~~executives~~ and ~~external~~ advisors ~~also took part~~participated in specific meetings, to provide information and clarifications requested by the ~~Committee.~~Committee to pursue the analysis conducted.

Earlier in the year, the Committee focused its activities in particular on the following topics:

i.

the periodic evaluation of Remuneration Policy implemented in ~~2018 in order~~2019, also with a view to ~~prepare~~developing new Policy Guidelines for the ~~proposed policy guidelines for 2019, providing for keeping~~2020-2023 term, electing to maintain the structure and the remuneration criteria ~~of remuneration of the~~for Directors and ~~Executives~~Managers with strategic responsibilities ~~defined in 2017 for the entire term, as regards in particular the simplified variable incentive system, as discussed in greater detail~~established in the ~~2017 Remuneration Report;~~previous term;

ii.

the review of the Company’s ~~2018~~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;

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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 ~~engagement activities held~~meeting conducted with ~~leading~~the main institutional investors and proxy advisors ~~in view of~~before the ~~general meeting,~~2020 Shareholder’s Meeting, in order to maximize shareholder consensus on the ~~2019~~2020-2023 Remuneration ~~Policy;~~Policy and on the 2020-2022 Long-Term Share Incentive Plan; these meetings where also attended by the Chairman of the Committee ~~also took part in the aforementioned meetings, bearing witness to~~underscoring the importance ~~given by~~that the Committee togives dialogue with shareholders;

~~vii.~~ix.

risk ~~assessment~~ and scenario ~~analysis,~~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 ~~support~~supporting of a leading consulting ~~firm;~~firm.

~~viii.~~
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 ~~start~~Committee performed training activities (“board induction”) with the competent corporate functions with the aim of ~~a further extensive dialogue~~providing the new Directors with ~~a broad range~~precise knowledge of ~~investors in~~its main duties and the ~~run-up to~~cycle of activities of the ~~annual meeting, with a view to promoting participation~~Remuneration Committee, as well as the structure, general criteria and ~~support~~remuneration levels provided for by the Eni Remuneration Policy.

In the second half of the year, the Committee examined the ~~2019~~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:

i—

finalized the proposal ~~(2019 grant)~~(2020 award) for the implementation of the ~~2017-2019~~2020-2022 Long Term Share Incentive Plane for the Chief Executive Officer and General Manager and for key management personnel;

ii

finalized the proposal on the exercise of the option to activate the non-compete agreement entered into with the Chief Executive Officer and General Manager, as set out in the 2019 Remuneration Report;

~~iii~~

~~started to examine the proposal for the Long-Term Share Incentive Plan 2020-2022 for key management personnel;~~

iv

~~examined the updating of remuneration benchmark studies and started to review the proposals for Remuneration Policy Guidelines for the 2020-2023 term;~~

v—

examined the general criteria for defining the ~~2020~~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 ~~conducting a preliminary analysis~~the Eni Remuneration Policy” approved on 12 March 2015 and ~~segmentation~~modified on 26 October 2017, to adapt its contents to the 2020-2023 Eni policy, in particular concerning the applicability of the ~~institutional investors that attended the 2019 Shareholders’ Meeting;~~malus clauses;

vi—

monitored developments in the legislative framework and market standards concerning the reporting of remuneration-related information, with a specific focus on ~~changes introduced with Legislative Decree no. 49/2019, transposing~~ the ~~SRD II, including a binding vote~~implementing measures of the ~~Shareholders’ Meeting on the Remuneration policy described~~EU Directive 828/2017 (SRD II), as well as developments in the ~~first section~~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 ~~Remuneration Report, and an advisory vote on the second section, concerning remuneration paid during the reporting period.~~COVID-19 pandemic.

The Committee scheduled ~~four~~seven meetings for ~~the first four months of 2020,~~2021, three of which ~~had~~have already been held as of the date of approval of this Report.

Control and Risk Committee

Members: ~~Alessandro Lorenzi~~Pietro Guindani (Chairman), ~~Andrea Gemma, Karina Litvack~~Ada Lucia De Cesaris, Nathalie Tocci and ~~Diva Moriani.~~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 Directors713 who possess the necessary expertise consistent with the duties they are required to perform814.

In particular, at their appointment, the Directors ~~Lorenzi, Litvack~~Guindani and ~~Moriani~~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) ~~and drafts~~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, onof 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, ontogether with any comments from the ~~main issues arising during the audit.~~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 ~~and~~

713

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.

814

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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~~oversees~~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 toby the Board onof 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, ~~including in its capacity as Guarantor of the Code of Ethics,~~ 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, ~~in relation to~~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, ~~for~~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 ~~May 9, 2017~~June 4, 2020 available to the public at the Company’s website.

Nomination Committee

Members: ~~Diva Moriani~~Ada Lucia De Cesaris (Chairman), ~~Andrea Gemma, Fabrizio Pagani~~Pietro Guindani and ~~Domenico Livio Trombone.~~Emanuele Piccinno.

The Nomination Committee is made up of non-executive Directors, a majority of whom are independent.

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a)

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;

b)

provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment falls under the Board’s 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;

c)

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;

d)

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;

e)

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;

f)

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;

g)

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;

h)

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

i)

periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible;

j)

provides its opinion to the Board of Directors on any activities carried out by the Directors in competition with the Company;

k)

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 ~~May 9, 2017,~~June 4, 2020, available to the public at the Company’s website.

Sustainability and Scenarios Committee

Members: ~~Pietro~~Karina A. ~~Guindani~~Litvack (Chairman), ~~Karina Litvack, Fabrizio Pagani~~Filippo Giansante, Emanuele Piccinno, Nathalie Tocci and ~~Domenico Trombone.~~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 ~~the~~ protection of rights, particularly of ~~the~~ 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 ~~April~~May 13, ~~2017~~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, ~~2019.~~2022.

Name	Position	Year first appointed to Board of Statutory Auditors
Rosalba Casiraghi	Chairman	2017
Enrico Maria Bignami	Auditor	2017
~~Paola Camagni~~Giovanna Ceribelli	Auditor	~~2014~~2020
~~Andrea Parolini~~Mario Notari (in office until September 1, 2020)	Auditor	~~2017~~2020
Roberto Maglio (in office from September 1, 2020)	Auditor	2020
Marco Seracini	Auditor	~~2014~~
~~Stefania Bettoni~~	~~Alternate~~	2014
Claudia Mezzabotta	Alternate	2017

~~Paola Camagni, Andrea Parolini,~~Giovanna Ceribelli, Mario Notari, Marco Seracini and ~~Stefania Bettoni~~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~~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

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•

examines reports from the CEO and the ~~CFO~~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

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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, ~~Adolfo Teobaldo De Girolamo, appointed by the Presidential Council of the Court of Auditors on December 22, 2014, until February 28, 2019.~~

~~As from March 1, 2019 the task is performed by the Magistrate of the Court of Auditors~~ Manuela Arrigucci, on the basis of the resolution approved onin 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 and the Control and Risk Committee.~~Auditors.

Employees

As of December 31, ~~2019,~~2020, Eni had a total of ~~32,053~~31,495 employees, with ~~an increase~~a decrease of ~~352~~558 employees, updown by ~~1.1%~~1.7% compared to December 31, ~~2018,~~2019, which mainly reflects an increase of ~~486~~78 employees working in Italy and a decrease of ~~134~~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 ~~of personnel headcount~~in the workforce in Italy ~~is mainly due to~~balanced by efficiency actions.

In addition we recorded the ~~execution~~consolidation of the ~~turn-over plan for guaranteeing~~subsidiary D-SHARE and the acquisition of Evolvere a ~~structure consistent with~~company engaged in the ~~objectives~~market of ~~starting up new businesses, rebalancing the business portfolio and enhancing the opportunities offered by new technologies.~~distributed generation from renewables in Italy.

Outside Italy the reduction of personnel headcount is mainly due to ~~some strategic operations including~~efficiency actions and the ~~transfer~~repatriation of employees to ~~third parties of Exploration & Production activities in Ecuador.~~Italy.

Employees at year end

	2019		2018		2017		2020		2019		2018
	(number)						(number)
Exploration & Production		11,502		11,645		11,970		9,815		10,272		10,448
Gas & Power		3,015		3,040		4,313
Global Gas & LNG Portfolio								700		711		734
Refining & Marketing and Chemicals		11,291		11,136		10,916		11,471		11,626		11,457
Eni gas e luce, Power & Renewables								2,092		7,388		2,056
Corporate and Other activities		6,245		5,880		5,735		7,417		2,056		7,006
		32,053		31,701		32,934		31,495		32,053		31,701

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The table below sets forth Eni’s employees as of December 31, ~~2017,~~ 2018, 2019 and ~~2019~~2020 in Italy and outside Italy:


		2019		2018		2017			2020		2019		2018
		(number)							(number)
Exploration & Production	Italy		4,556		4,531		4,510	Italy		3,692		3,491		3,477
	Outside Italy		6,946		7,114		7,460	Outside Italy		6,123		6,781		6,971
			11,502		11,645		11,970			9,815		10,272		10,448
Gas & Power	Italy		2,040		2,089		2,282
Global Gas & LNG Portfolio								Italy		290		293		318
	Outside Italy		975		951		2,031	Outside Italy		410		418		416
			3,015		3,040		4,313			700		711		734
Refining & Marketing and Chemicals	Italy		8,901		8,740		8,580	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		2,390		2,396		2,336	Outside Italy		413		358		337
			11,291		11,136		10,916			2,092		2,056		2,056
Corporate and other activities	Italy		5,991		5,642		5,501	Italy		6,999		6,971		6,625
	Outside Italy		254		238		234	Outside Italy		418		417		381
			6,245		5,880		5,735			7,417		7,388		7,006
Total	Italy		21,488		21,002		20,873	Italy		21,575		21,488		21,002
	Outside Italy		10,565		10,699		12,061	Outside Italy		9,920		10,565		10,699
			32,053		31,701		32,934			31,495		32,053		31,701
of which senior managers			1,031		1,016		1,012			982		1,037		1,025

We seek to maintain constructive relationship with labor unions.

Share ownership

As of February 28, ~~2020,~~2021, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was ~~269,178~~256,855 less than 0.1% of Eni’s share capital outstanding as of the same date. Eni issues only ordinary shares, each bearing ~~one-vote right;~~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. ~~Furthermore, on March 19, 2020, the CEO of Eni purchased on the open market 29,300 shares.~~

Name

Position

Number of
shares owned

Board of Directors

~~Emma Marcegaglia~~

~~Chairman~~

~~87,010(1)~~

Claudio Descalzi

CEO

68,755~~(2)~~

Board of

Statutory Auditors

~~Statutory Auditors~~Marco Seracini

Auditor

~~none~~2,000

Senior Managers

~~142,713~~186,100~~(3)~~(1)

(1)

Of which No. ~~597 shares held under Asset Management, No. 7,143 shares held under Asset Management jointly a third person, and No. 45,000 shares held in bare ownership jointly with a third person.~~

~~(2)~~

~~Updated as of March 19, 2020.~~

~~(3)~~

~~Of which No. 6,890~~20,000 shares owned by ~~wives~~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, ~~2020,~~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%116 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 4.34
Cassa Depositi e Prestiti SpA 936,179,478 25.76

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, ~~2020,~~2021, the percentage of Eni’s treasury shares was equal to ~~1.70%~~0.92% of the share capital219.

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, ~~2020,~~2021, there were ~~33,623,608~~25,987,995 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately ~~1.9%~~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 ~~companies.~~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.

~~(1)~~16

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.

~~(2)~~17

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.

18

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.

19

In ~~its~~the meeting of February 27, ~~February~~ 2020, Eni’s Board of Directors resolved to submit to the Shareholder’s Meeting, to be held on May 13, ~~May~~ 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.

20

For more details on internal rules on related parties transactions, please refer to Item 10, paragraph “Interests in Company’s transactions”.

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~~Item 8. FINANCIAL INFORMATION~~

~~Consolidated Statements and other financial information~~

~~See “Item 18 – Financial Statements”.~~

~~Legal proceedings~~

~~Eni is a party~~In addition to ~~a number of civil actions and administrative arbitral and other judicial~~ proceedings arising in the ordinary course of ~~business. Based on information available~~business referred to ~~date,~~above, Eni is party to other proceedings, and ~~taking into account~~a description of the ~~existing risk provisions disclosed~~most significant proceedings currently pending is provided in “Item 18 — Note 2027 to the Consolidated Financial ~~Statements~~Statements. Generally and ~~that in some instances~~unless otherwise indicated, these legal proceedings have not been provisioned because Eni believes a negative outcome ~~is not probable~~to be unlikely or it is not possible to make a reliable estimates of contingency losses, Eni believes that these legal proceedings will likely not have a material adverse effect on Eni’s Consolidated Financial Statements.

~~For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see “Item 18 – Note 27~~because the amount of the ~~Notes on Consolidated Financial Statements”.~~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 ~~scenario evolution. For~~evolution in the ~~year~~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, ~~management is planning~~last July we defined a new distribution policy aimed at giving visibility and certainty to ~~distribute~~our shareholders in a ~~full-year~~period of great volatility.

Our remuneration policy was structured on two pillars: (i) a fixed dividend of ~~€0.89~~€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 ~~by approximately 3.5% vs. 2019.~~ 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.”

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. For further details see “Item 3 –— Risk factors”.

At the General Shareholders’ Meeting scheduled onfor May ~~13, 2020,~~12, 2021, management intends to propose the distribution of a dividend of ~~€0.86~~€0.36 per share for fiscal year ~~2019,~~2020, of which ~~€0.43~~€0.12 already paid as interim dividend in September ~~2019.~~

2020. Total cash outlay for the ~~2019~~2020 final dividend is expected at approximately ~~€1.5~~€0.86 billion to be paid in ~~2020~~2021 (whereas ~~€1.5~~€0.43 billion were distributed in September ~~2019)~~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.

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Markets

Consob is the public authority responsible for regulating and supervising the Italian ~~securities~~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, ~~inter alia,~~among the others, regulated markets in ~~Italy; it~~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 ~~responsibility for supervision (Consob~~the supervisory tasks (to be performed by Consob and the Bank of Italy) from ~~that of~~the tasks relating to market management ~~(Borsa~~(to be performed by Borsa Italiana). ~~Main responsibilities~~The mainresponsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading ~~and~~as well as the surveillance of the markets.

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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.~~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~~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”121 (“MSG”), which has been in effect from January 1, 2011222 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 ~~Chairman~~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 ~~2019,~~2020, see the Remuneration Report ~~2020~~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.

~~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~~3~~, fully paid, and is represented by 3,634,185,330 ordinary registered shares without indication of par value. As required by the Italian law on the dematerialization of financial instruments,~~

~~(1)~~21

The Board of Directors modified this Management System Guideline on January 19, 2012 and lastly on April 4, 2017.

~~(2)~~22

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.

~~(3)~~

In its meeting of 27 February 2020, Eni’s Board of Directors resolved to submit to the Shareholders’ Meeting, convened on May 13, 2020, the proposal of cancellation of treasury shares acquired in 2019.

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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~~(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 ~~30, 2020,~~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 onfor 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.

24

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.

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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.

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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 ~~shareholders’ agreement with~~full disclosure of the ~~buyer is taken into account in~~resolution, act or transaction, or of the ~~calculation~~acquisition of ~~above mentioned relevant~~the shareholdings.

With particular reference to the power referred to in letter b), until the ~~legislation establishes notification obligations for the buyer entity outside of the EU to the Italian Presidency of the Council of Ministers as well as procedural terms. Until such~~ 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.

~~(4)~~

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.

~~(5)~~

The prior provisions (Article 2 of Decree Law No. 332/1994, ratified by Law No. 474/1994 and its implementing decrees), as well as the provisions of the By-laws which were inconsistent with the new rules, lapsed at the issuance of Decree of the President of the Italian Republic No. 85 of March 25, 2014, in force since June 7, 2014.

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For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria930. 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 investments1031.

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 ~~months.~~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

~~(6)~~

~~Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.~~

~~(7)~~

~~Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.~~

~~(8)~~

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 an elevated current market value and particularly extensive shareholding structure.

~~(9)~~

~~Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.~~

~~(10)~~

~~Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.~~

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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.

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Income tax

Dividends regarding income of financial year ~~2019~~2020 to be paid in ~~2020,~~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

~~(11)~~

~~Autorità garante per la concorrenza e il mercato (AGCM – www.agcm.it)~~

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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

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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);

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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~~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

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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.

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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,~~Shipping) that isare 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. ~~The~~With respect to the commodity risk ~~of each business unit (Eni’s business lines or subsidiaries) is pooled~~Eni Trade & Biofuels and ~~managed by the parent company Midstream business department, with~~ Eni ~~Trading & Shipping executing~~Global Energy Markets centralize the negotiation of ~~commodity derivatives.~~financial instruments on the markets.

~~During 2013,~~In 2021, the above mentioned centralized model for the execution of financial ~~derivatives~~instrument has been ~~ring fenced~~updated in light of the relevant ~~new~~changes in the main financial regulations ~~which became effective (EMIR/~~(Mifid II/EMIR/Dodd Frank act). Eni’s activities are in compliance with regulatory requirements for execution of financial ~~derivatives~~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 ~~new~~ financial regulation, in 2013 the EMIR concepts of “risk reducing” and “non-risk reducing” derivatives were introduced. Company’s activities in financial ~~derivatives~~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 ~~derivative~~financial instrument can be qualified aas risk reducing ~~instrument~~ 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.

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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 ~~protect~~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 ~~protect~~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

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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~~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.

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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.
~~(4)~~ (5)	Distribution of securities other than ADSs ~~pursuant to (i) stock dividends~~ or ~~other free stock distributions, or (ii) an exercise of~~ rights to purchase additional ~~ADSs.~~ 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.
~~(5)~~ ~~Distribution of securities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares).~~ (6)	~~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 ~~U.S.~~ SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.

For the year ~~2019,~~2020, the Depositary ~~will reimburse~~reimbursed to Eni ~~up to~~ $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.~~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 ~~Chief~~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 ~~Chief~~the Head of Eni’s Accounting and Financial ~~Officer,~~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 ~~Chief~~the Head of Eni’s Accounting and Financial ~~Officer~~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 ~~Chief~~Head of Eni’s Accounting and Financial ~~Officer,~~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, ~~2019.~~2020.

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~~EY SpA has served as Eni principal independent public auditor for fiscal year 2018.~~

The following table shows total fees for services rendered to Eni by its public auditors PwC SpA and ~~its~~ member firms of ~~PwC Network~~its network for the ~~year~~years ended December 31, ~~2019. The amount shown for the year ended December 31, 2018 have been paid to EY SpA~~2020 and ~~its respective member firms which has served as Eni principal independent public auditor since the fiscal year 2018.~~2019.

	Year ended December 31,				Year ended December 31,
	2019		2018		2020		2019
	(€ thousand)				(€ thousand)
Audit fees		15,748		25,445		19,605		15,748
Audit -related fees		1,045		1,628
Audit-related fees						1,412		1,045
Tax fees
All other fees
Total		16,793		27,073		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. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value-added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities.

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 ~~2019,~~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.

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Item 16E. Purchases of equity securities by the issuer and affiliated purchasers

~~The Eni Board of Directors, in execution~~In the course of the authorization granted by the Eni Shareholders’ Meeting of May 14, 2019 and in accordance with the terms announced to the market on that date, has approved measures to begin the 2019 share buy-back programme, in the maximum amount of €400,000,000year 2020 and up to ~~a maximum~~the date of ~~67,000,000 shares. The purchases started in~~this report, none of the ~~first week~~Company or its affiliated purchasers have executed any purchase of ~~June~~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 ~~in the month of~~ December ~~2019.~~31, 2020.

Period Total number
of shares
purchased Average
price paid
per share Total number of
shares purchased
as part of publicly
announced plans
or programs Total
purchase
cost Approximate
€ value of Shares
that may yet be
purchased under
the plans or
programs
€ per share (million €) (million €)
Start of the program June 5 – June 30, 2019 3,690,860 14.21 3,690,860 52 348
1 July – 31 July 2019 5,660,592 14.48 5,660,592 82 266
1 August – 31 August 2019 3,339,795 13.49 3,339,795 45 221
1 September – 30 September 2019 3,543,252 13.96 3,543,252 49 171
1 October – 31 October 2019 5,914,499 13.77 5,914,499 81 90
1 November – 30 November 2019 4,584,298 14.03 4,584,298 64 25
1 December – 31 December 2019 1,857,186 13.65 1,857,186 25 0
Total as of December 31, 2019 28,590,482 13.99 28,590,482 400

Item 16F. Change in Registrant’s Certifying Accountant

Due to the audit firm rotation rules in Italy, EY, as the Company’s independent public accounting firm, stepped down at the meeting of the Company’s shareholders on May 14, 2019. EY was hired for a period of nine years and served as our independent auditor for the fiscal years ended December 31, 2010 through 2018.Not Applicable

EY report on the Company’s financial statements for each of the past nine years did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope or accounting principle.

In connection with the audit of the Company’s financial statements in the fiscal years ended December 31, 2018 and 2017, there were no disagreements with EY on any matters of accounting principles or practices, financial statement disclosure, or auditing scope and procedures which, if not resolved to the satisfaction of EY, would have caused EY to make reference to the matter of such disagreements in their reports.

Eni has provided a copy of this disclosure to EY and requested that EY furnish us with a letter addressed to the SEC stating whether or not it agrees with the above statements. A copy of EY’s letter is filed as an exhibit to this Form 20-F.

The Statutory Board of Auditors selected PricewaterhouseCoopers SpA to be appointed as the Company’s new independent registered public accounting firm for the nine-year period from 2019 to 2027, which was approved by Eni’s shareholders on May 14, 2019.

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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. ~~During 2019, Eni’s independent Directors had opportunities to meet, informally, to hold discussions and exchange opinions.~~

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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.~~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 ~~Andrea Gemma.~~Nathalie Tocci . The other members include ~~directors Pietro Guindani, Alessandro Lorenzi~~Directors Karina A. Litvack, and ~~Diva Moriani.~~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 (https://www.eni.com/docs/en_IT/enicom/company/governance/rules-of-the-remuneration-committee.pdf).~~ 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.

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PART III

Item 17. FINANCIAL STATEMENTS

Not applicable.

Item 18. FINANCIAL STATEMENTS

Index to Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheet as of December 31, ~~2019~~2020 and December 31, ~~2018 and January 1, 2018~~2019		F-5
Consolidated profit and loss account for the years ended December 31, 2020, 2019 ~~2018~~ and ~~2017~~2018		F-6
Consolidated Statements of comprehensive income for the years ended December 31, 2020, 2019 ~~2018~~ and ~~2017~~2018		F-7
Consolidated Statements of changes in shareholders’ equity for the years ended December 31, 2020, 2019 ~~2018~~ and ~~2017~~2018		F-8
Consolidated Statement of cash flows for the years ended December 31, 2020, 2019 ~~2018~~ and ~~2017~~2018		F-11
Notes on Consolidated Financial Statements		~~F-13~~F-15

Item 19. EXHIBITS

1.	1.			By-laws of Eni SpA ~~(incorporated by reference to Exhibit 1 to Form 20-F 2018 (File No.001-14090) filed on April 5, 2019)~~
2.	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.	~~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	~~12.1.~~
12.2.	Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
~~12.2.~~ 13.1.	~~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 towith Italian listing standards for the year ~~2019~~2020 incorporated herein by reference
15.a(ii)	~~15.a(ii)~~			Report of DeGolyer and MacNaughton
15.a(iii)	~~15.a(iii)~~			Report of Ryder Scott Co
~~15.a(v)~~			~~Letter of EY dated as of April 2, 2020~~
101.a(i)	XBRL Document

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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~~Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance ~~sheet~~sheets of Eni SpA and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated profit and loss ~~account~~accounts and consolidated statements of comprehensive income, changes in shareholders’ equity and cash flows for each of the ~~year then~~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, ~~2019,~~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 ~~year then~~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, ~~2019,~~2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the COSO.

Change in Accounting Principle

As discussed in Note 31 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

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procedures also included, among others, testing the ~~significant assumptions relating to the estimates of proved oil~~completeness and ~~natural gas reserves also involved obtaining evidence to support the reasonableness~~accuracy of the ~~assumptions, including~~data related to future development costs and operating costs. Additionally, these procedures included evaluating whether the assumptions ~~used~~applied to the data related to future development costs and operating costs were reasonable considering the past ~~and current~~ performance of the ~~Company,~~Company.

Impairment Assessment of Certain Proved Oil and ~~whether they were consistent with evidence in other areas of the audit.~~

~~Legal Proceedings Concerning Administrative Corporate Responsibility and Other Proceedings~~Natural Gas Properties

As described in Notes 1, 11 and 2714 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 ~~recognizes provisions as liabilities~~incurred impairment losses before taxes associated with the proved oil and natural gas properties in the ~~consolidated financial statements when (i) there~~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 ~~a present obligation, legal~~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 ~~constructive, as a result~~group of assets. The recoverability of a ~~past event; (ii) it~~CGU is ~~probable that an outflow~~assessed by comparing its carrying amount with the recoverable amount, which is the higher of ~~resources embodying economic benefits will~~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 ~~required~~derived from continuing use of the CGU and, if significant and reliably measurable, the cash flows expected to ~~settle~~be obtained from its disposal at the ~~obligation;~~end of its useful life, after deducting the costs of disposal. For oil and ~~(iii)~~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 the obligation can be reliably estimated. 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 uncertainproduction is based on assumptions related to future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amounts cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Eni is a party in a number of civil actionscommodity prices, lifting and ~~administrative arbitral~~development costs, field decline rates, market demand and other judicial proceedings arising in the ordinary course of business, including proceedings related to Block OPL 245 — Nigeria, Congo and Criminal Proceeding no. 12333/2017. No provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably. The Company does not recognize contingent liabilities in the financial statements but discloses them within the footnotes to the consolidated financial statements.factors.

The principal considerations for our determination that performing procedures relating to ~~legal proceedings concerning administrative corporate responsibility~~the impairment assessment of certain proved oil and ~~other proceedings~~natural gas properties is a critical audit matter are (i) the significant ~~judgement exercised~~judgment by management, including the use of specialists, when ~~assessing~~developing the ~~likelihood~~value in use of ~~a loss being incurred for the proceedings relating to Block OPL 245 — Nigeria, Congo~~proved oil and ~~Criminal Proceeding no. 12333/2017 can be made, which in turn led to~~natural gas properties; (ii) a high degree of auditor ~~judgement,~~judgment, subjectivity, and effort in performing procedures and evaluating management’s ~~assessment~~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 ~~the loss contingencies associated~~professionals with ~~the legal contingencies.~~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 ~~evaluation of legal claims~~proved oil and contingencies, including controls over determining whether a loss is probable for the proceedings relating to Block OPL 245 — Nigeria, Congo and Criminal Proceeding no. 12333/2017, as well as the sufficiency of financial statement disclosures.natural gas properties impairment assessment. These procedures also included, among others ~~obtaining~~(i) testing management’s process for developing the value in use of proved oil and natural gas properties; (ii) evaluating the ~~letters~~appropriateness of ~~audit inquiry with external legal counsel,~~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 ~~assessment regarding whether an unfavorable outcome is reasonably possible or probable, and~~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 ~~sufficiency~~reasonableness of the ~~Company’s legal contingency disclosures.~~assumptions as compared to the past performance of the Company. Professionals with specialized skill and knowledge were used to assist in ~~evaluating~~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 ~~management’s~~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 ~~noted above.~~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, ~~2020~~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)~~“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 ~~each of the two years in~~ 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 atas of December 31, 2018, and the results of its operations and its cash flows for ~~each of the two years in~~ 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 ~~2019~~2020 only and does not form part of Eni S.p.A.’s Annual Report for 2018.

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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(€ million)


	Note		2019		2018		2017		Note		2020		2019		2018
Net profit				155		4,137		3,377
Profit (loss)												(8,628)		155		4,137
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans		(25)		(42)		(15)		(33)		(25)		(16)		(42)		(15)
Share of other comprehensive income (loss) on equity-accounted investments related to benefit plans remeasurements		(25)		(7)
Share of other comprehensive income (loss) on equity-accounted investments										(25)				(7)
Change of minor investments measured at fair value with effects to other comprehensive income		(25)		(3)		15				(25)		24		(3)		15
Tax effect		(25)		5		(2)		29		(25)		25		5		(2)
				(47)		(2)		(4)				33		(47)		(2)
Items that may be reclassified to profit or loss in later periods
Currency translation differences		(25)		604		1,787		(5,573)		(25)		(3,314)		604		1,787
Change in the fair value of available-for-sale financial instruments								(5)
Change in the fair value of cash flow hedging derivatives		(25)		(679)		(243)		(6)		(25)		661		(679)		(243)
Share of other comprehensive income (loss) on equity-accounted investments		(25)		(6)		(24)		69		(25)		32		(6)		(24)
Tax effect		(25)		197		58		1		(25)		(192)		197		58
				116		1,578		(5,514)				(2,813)		116		1,578
Total other items of comprehensive income (loss)				69		1,576		(5,518)				(2,780)		69		1,576
Total comprehensive income (loss)				224		5,713		(2,141)				(11,408)		224		5,713
Attributable to Eni				217		5,702		(2,144)				(11,415)		217		5,702
Attributable to non-controlling interest				7		11		3				7		7		11
				224		5,713		(2,141)

See the accompanying notes.

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CONSOLIDATED STATEMENT OF CASH FLOWS
(€ million)

Note 2019 2018 2017
Net profit 155 4,137 3,377
Adjustments to reconcile net profit to net cash provided by operating activities
Depreciation and amortization (11) (12) (13) 8,106 6,988 7,483
Net Impairments (reversals) of tangible and intangible assets and
right-of-use assets (14) 2,188 866 (225)
Write-off of tangible and intangible assets (11) (13) 300 100 263
Share of (profit) loss of equity-accounted investments (15) (31) 88 68 267
Net gain on disposal of assets (170) (474) (3,446)
Dividend income (31) (247) (231) (205)
Interest income (147) (185) (283)
Interest expense 1,027 614 671
Income taxes (32) 5,591 5,970 3,467
Other changes (179) (474) 894
Changes in working capital:
- inventories (200) 15 (346)
- trade receivables 1,023 334 657
- trade payables (940) 642 284
- provisions 272 (238) 96
- other assets and liabilities 211 879 749
Cash flow from changes in working capital 366 1,632 1,440
Net change in the provisions for employee benefits (23) 109 38
Dividends received 1,346 275 291
Interest received 88 87 104
Interest paid (1,029) (609) (582)
Income taxes paid, net of tax receivables received (5,068) (5,226) (3,437)
Net cash provided by operating activities 12,392 13,647 10,117
- of which with related parties (36)
(6,356)

(2,707)

(2,843)

Investing activities:
- tangible assets (11)
(8,049)

(8,778)

(8,490)

- prepaid right-of-use assets (12)
(16)

- intangible assets (13)
(311)

(341)

(191)

- consolidated subsidiaries and businesses net of cash and cash equivalent acquired (26) (5) (119)
- investments (15)
(3,003)

(125)

(510)

- securities held for operating purposes (8) (8)
- financing receivables held for operating purposes (229) (358) (585)
- change in payables in relation to investing activities (307) 408 152
Cash flow from investing activities (11,928) (9,321) (9,624)
Disposals:
- tangible assets 264 1,089 2,745
- intangible assets 17 5 2
- consolidated subsidiaries and businesses net of cash and cash equivalent disposed of (26) 187 (47) 2,662
- tax on disposals (3) (436)
- investments 39 195 482
- securities held for operating purposes 17 15 1
- financing receivables held for operating purposes 178 279 493
- change in receivables in relation to disposals 95 606 (434)
Cash flow from disposals 794 2,142 5,515
Net change in securities and financing receivables held for non-operating purposes(a) (279) (357) 341
Net cash used in investing activities (11,413) (7,536) (3,768)
- of which with related parties (36) (2,912) (3,314) (3,115)

~~See the accompanying notes.~~

~~(a)~~

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 accordance to applicable listing standards. 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 cash flow statements of comparative periods have been reclassified accordingly.


	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	2019		2018		2017		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)		1,811		3,790		1,842	(18)		5,278		1,811		3,790
Repayments of long-term financial debt	(18)		(3,512)		(2,757)		(2,973)	(18)		(3,100)		(3,512)		(2,757)
Payments of lease liabilities	(12)		(877)					(12)		(869)		(877)
Increase (decrease) in short-term financial debt	(18)		161		(713)		(581)	(18)		937		161		(713)
			(2,417)		320		(1,712)
Dividends paid to Eni’s shareholders			(3,018)		(2,954)		(2,880)			(1,965)		(3,018)		(2,954)
Dividends paid to non-controlling interest			(4)		(3)		(3)			(3)		(4)		(3)
Reimbursements to non-controlling interest			(1)									(1)
Acquisition of additional interests in consolidated subsidiaries			(1)									(1)
Acquisition of treasury shares			(400)									(400)
Issue of perpetual subordinated bonds								(25)		2,975
Net cash used in financing activities			(5,841)		(2,637)		(4,595)			3,253		(5,841)		(2,637)
- of which with related parties	(36)		(817)		16		(16)	(36)		164		(817)		16
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)			(7)				7
Effect of exchange rate changes and other changes on cash and cash equivalents			8		18		(72)			(69)		1		18
Net increase (decrease) in cash and cash equivalents			(4,861)		3,492		1,689			3,419		(4,861)		3,492
Cash and cash equivalents – beginning of the year	(5)		10,855		7,363		5,674	(5)		5,994		10,855		7,363
Cash and cash equivalents – end of the year(b)	(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.

~~(b)~~

In 2018, cash and cash equivalents at the end of the year included €19 million of cash and cash equivalents of consolidated subsidiaries held for sale that were reported in the item “Assets held for sale”.

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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 ~~Eni Group~~Group) have been prepared on a going concern1 basis in accordance with International Financial Reporting Standards (IFRS)12 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 ~~2019~~2020 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on ~~March 18, 2020,~~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 ~~proved and proved developed~~ 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.

1

With reference to the impacts of COVID-19, see information provided in the previous paragraph.

2

IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).

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~~Subsidiaries are consolidated, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases.~~ Assets, liabilities, income and expenses of consolidated subsidiaries are fully recognised with those of the parent in the Consolidated Financial ~~Statements;~~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 isare presented in a specific line ~~item of~~items, respectively, in the profit and loss ~~account.~~account and in the statement of comprehensive income.

~~For entities~~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,~~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. ~~Some subsidiaries are~~The abovementioned exclusions do not ~~consolidated because they are immaterial, either individually or in the aggregate; this exclusion has not produced~~produce material23 ~~effects~~ impacts on the Consolidated Financial Statements34.

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 ~~shareholders’~~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 account45. 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~~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”.

23

According to ~~the requirements of the Conceptual Framework for Financial Reporting, “~~IFRSs, information is material if omitting, itmisstating or ~~misstating it~~obscuringit could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial ~~information about a specific reporting entity~~”.statements.

34

Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”.

45

Conversely, any amount related to the former subsidiary previously recognised in other comprehensive income, which may not be ~~reclassifiedsubsequently~~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 ~~also~~ 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.5 6

Under the equity method, investments are initially recognised at cost, allocating it, similarly to business combinations procedures, ~~the purchase price of the investment~~ to the investee’s identifiable assets/liabilities; ifany 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 ~~its carrying amount~~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.

5

In the case of step acquisition of significant influence (joint control), the investment is recognised, at the acquisition date of significant influence (joint control), at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity.

6

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.

7

If the retained investment continues to be classified either as a joint venture or an associate and so accounted for using the equity method, no remeasurement at fair value is recognised in the profit and loss account.

8

Conversely, any amount related to the former joint venture/associate previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

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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)~~; as an alternative, non-controlling interests may be measured at fair value, which means that goodwill includes the portion attributable to them (full goodwill method)~~.10~~. The choice of measurement basis for goodwill (partial goodwill method vs. full goodwill method) is made on a transaction-by-transaction basis.~~

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.

9

~~Fair value measurement principles are described in the accounting policy for “Fair value measurements”.~~

10

~~The choice between the partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account.~~

11

~~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 ~~shareholders’~~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 2019		Exchange rate at December 31, 2019		Annual average exchange rate 2018		Exchange rate at December 31, 2018		Annual average exchange rate 2017		Exchange rate at December 31, 2017		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		1.12		1.12		1.18		1.15		1.13		1.20		1.14		1.23		1.12		1.12		1.18		1.15
Pound Sterling		0.88		0.85		0.88		0.89		0.88		0.89		0.89		0.90		0.88		0.85		0.88		0.89
Australian Dollar		1.61		1.60		1.58		1.62		1.47		1.53		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

12

When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are 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~~(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, ~~as well as whether~~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

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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 ~~buy-back~~service contracts

Oil and gas reserves related to Production Sharing Agreements ~~and buy-back contracts~~ 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. ~~Initially, all booked~~Proved reserves can be classified as developed or undeveloped. Volumes are classified asinto proved ~~undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved~~ developed reserves as a consequence of development activity. Generally, reserves are booked as proved developed ~~when~~at the ~~first oil or gas is produced.~~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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Leases1314

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.

InThe depreciation charges of the ~~oil~~right-of-use asset and ~~gas activities,~~ the ~~operator~~interest expenses on the lease liability directly attributable to the construction of an ~~unincorporated joint operation which enters into a lease contract~~asset are capitalised as part of the ~~sole signatory recognises on the balance sheet: (i) the entire lease liability if, based on~~cost of such asset and

13

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.

14

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.

15

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.

16

Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognising the lease payments associated with those leases as an expense on a straight-line basis over the lease term.

17

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.

18

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.

19

Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained.

20

Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the 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 ~~made~~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. This condition is normally met when: (i) the intangible asset arises from contractual or other legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or together with other assets. An entity controls an intangible asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits.

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~~21 .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. 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.

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

21

The accounting policies adopted until 2017 (before applying IFRS 15) required the capitalisation of directly attributable customer acquisition costs when all the following conditions were met: (i) the capitalised costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenue from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.

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In particular, in estimating value in use, the cash outflows for forestry projects2221 are included, consistent with the ~~medium term target~~targets of the decarbonization strategy, within the expected operating cash ~~outflows of the segment whose emissions are offset. Currently,~~outflows; in this regard, considering that the forestry projects can be developed in countries where Eni does not carry out operating activities and ~~considering~~given the difficulty to allocate such cash outflows, on a reasonable and consistent basis, to ~~the~~ 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 & ~~Power~~LNG Portfolio (GGP) segment, ~~and~~ 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.2322

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.~~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.

2221

For the recognition criteria of forestry certificates see the accounting policy for “Costs”.

2322

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 ~~“Other~~“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 ~~assessesed~~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 instruments24

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.

24

The accounting policies related to financial instruments were defined on the basis of IFRS 9 “Financial Instruments” effective from 2018; as required by the accounting standard, the new requirements have been applied starting from January 1, 2018 without restating the comparative information. With reference to the financial instruments held by the Company, the previous accounting policies (applied until2017) required essentially: (i) the classification of financial assets on the basis of the categories under IAS 39; (ii) recognition and measurement of impairment losses if there was objective evidence that an impairment loss had been incurred (the so-called incurred loss model); and (iii) more stringent hedge accounting requirements (mainly referred to the assessment of hedge effectiveness).

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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.2625

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

25

~~Receivables and other financial assets measured at amortised cost are presented on the balance sheet net of their loss allowance.~~

26

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

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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

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dismantle, remove and restore items of property, plant and equipment is complex. It requires management

27

These liabilities relate essentially to the Exploration & Production segment’s assets. The decommissioning and restoration liabilities associated with the Refining & Marketing and Chemical and Gas & Power segments’ assets are generally not recognised, as the obligations cannot be reliably estimated, given their indeterminate settlement dates. In this regard, Eni performs periodic reviews of Refining & Marketing and Chemical and Gas & Power segments’ tangible assets for any changes in facts and circumstances that might require recognition of a decommissioning and restoration 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.

28

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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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

29

~~The current share-based incentive plan, to be settled by treasury shares, was approved by the shareholders’ meeting held on April 13, 2017.~~

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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.

30

In accordance with the accounting policy adopted until 2017 (entitlement method, before applying IFRS 15), revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers were recognised on the basis of Eni’s net working interest in those properties. On the balance sheet, lifting imbalances were recognised respectively as payables and receivables and measured at current prices at the balance sheet date.

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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

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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. After the disposal, any retained interest in the investee is measured in accordance with the measurement criteria indicated in the accounting policy for “Investments in equity instruments”, unless the retained interest continues to be an equity-accounted investment.

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

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expected to be realised/settled in the entity’s normal operating cycle or within twelve months after the

31

The impacts on the primary financial statements arising from the adoption, starting from January 1, 2019, of the new IFRSs, as well as the other changes in the primary financial statements, are described in note 3 — Changes in accounting policies.

32

~~Further information about classification of financial instruments is provided in note 27 — Guarantees, commitments and risks — Other information about financial instruments.~~

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in IFRS 3; (ii) provide clarifications on the requirements for recognising, at the acquisition date, provisions, contingent liabilities and IFRS 7 “Interest Rate Benchmark Reform” (hereinafter amendments to IFRS 9, IAS 39 and IFRS 7), which provide temporary exceptions from applying specific hedge accounting requirements to all hedging relationships directly affected by the interest rate benchmark reform.levies assumed in a business combination; (iii) state explicitly that a contingent asset acquired in a business combination cannot be recognised. The amendments ~~to IFRS 9, IAS 39 and IFRS 7~~ shall be applied for annual reporting periods beginning on or after January 1, ~~2020.~~

2022;

35•

~~In previous reporting periods, income tax receivables and income tax payables were recognised within~~ the ~~non-current section of the balance sheet, respectively, in the line items “Other assets” and “Other liabilities”.~~

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Generally, trade receivables do not bear interest and provide payment terms within 180 days.

Trade receivables decreased by ~~€1,001~~€1,432 million ~~of which €874 million related~~due to the ~~Gas & Power segment following a~~ drop in prices ~~and volumes~~ of ~~gas sold in the fourth quarter 2019 compared to the same period of 2018.~~hydrocarbons.

At December 31, ~~2019,~~2020, Eni sold without recourse receivables due in ~~2020~~2021 for ~~€1,782~~€1,377 million (€~~1,769~~1,782 million at December 31, ~~2018~~2019 due in ~~2019)~~2020). Derecognized receivables in 2020 related ~~to the Gas & Power segment for €1,369 million and~~ to the Refining & Marketing and Chemical ~~business line~~segment for ~~€413 million.~~

~~Receivables from divestments decreased by €92~~€730 million, ~~during 2019 due~~ to the ~~collection of the last installment of €123~~Eni gas e luce, Power & Renewables segment for €324 million ~~related~~and to the ~~sale of a 10% interest in the Zohr asset in Egypt made to BP in 2017.~~Global Gas & LNG Portfolio segment for €323 million.

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payment, number of claims, etc.); (iii) presence of mitigation factors of the credit risk (e.g. securitization package, insurance against the credit risk, guarantee from third parties, etc.); (iv) other specialized pieces of information obtained by the Company’s business commercial departments or by specialized info-providers; (v) industrial and market trends. Internal ratings and the probability of default are constantly updated by means of back-testing analysis and risk assessment of the current credit portfolio. The loss given default associated with those industrial customers is estimated by the business departments based on the past experience in credit recoverability; in the case of defaulting customers, loss given default is estimated based on the recovery rates obtained in situations of credit restructurings or litigation procedures.

The probability of default associated with NOCs and public administrations is estimated based on the country risk premium incorporated in the risk-adjusted weighted average cost of capital utilized by the Company to perform the impairment review of its fixed assets. The loss given default of these business partners, essentially represented by the probability of a delay in repaying due amounts, is estimated based on historical averages of delays in collecting overdue receivables, substantially assessing the time value of money. The resulting loss given default is adjusted to factor in any existing mitigation factor. In case of particular market conditions or sovereign defaults, the expected loss associated with NOCs is re-rated based on the empirical evidence and outcomes obtained from restructuring of sovereign debts considering the specificities of trading relationships with energy companies. Customers of the Eni subsidiary “Eni gas e luce”, which engages in marketing gas and power to residential customers, were grouped into homogeneous clusters with different credit risk and probability of default which have been estimated based on past experience on credit collection, systematically updated and, in case of particular market conditions, adjusted to take into account expected market and credit trends in any given cluster.

The exposure to credit risk and expected losses relating to ~~retail~~ customers of the ~~Gas & Power segment~~Eni gas e luce business line was assessed based on ~~the basis of~~ 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, 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
December 31, 2018
Customers – Eni gas e luce:
- Retail 575 49 34 64 554 1,276
- Middle 449 43 13 29 349 883
- Other 207 2 1 2 3 215
Gross amount 1,231 94 48 95 906 �� 2,374
Allowance for doubtful accounts (20) (18) (18) (56) (745) (857)
Net amount 1,211 76 30 39 161 1,517
Expected loss (%)
1.6 19.1 37.5 58.9 82.2 36.1

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Net (impairment losses) reversals of trade and other receivables are disclosed as follows:

(€ million)	2019		2018		2020		2019		2018
Net (impairment losses) reversals of trade and other receivables
New or increased provisions		(620)		(498)		(343)		(620)		(498)
Credit losses		(45)		(37)
Net credit losses						(36)		(45)		(37)
Reversals		233		120		153		233		120
		(432)		(415)		(226)		(432)		(415)

Receivables with related parties are disclosed in note 36 — Transactions with related parties.

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10 Other assets and liabilities

(€ million)	December 31, 2019								December 31, 2018								December 31, 2020								December 31, 2019
	Assets				Liabilities				Assets				Liabilities				Assets				Liabilities				Assets				Liabilities
	Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current
Fair value of derivative financial instruments		2,573		54		2,704		50		1,594		68		1,445		40		1,548		152		1,609		162		2,573		54		2,704		50
Contract liabilities						1,669		456						1,108		518						1,298		394						1,669		456
Other Taxes		766		223		1,411		63		561		254		1,432		34		450		181		1,124		26		766		223		1,411		63
Other		633		594		1,362		1,042		664		302		1,427		883		688		920		841		1,295		633		594		1,362		1,042
		3,972		871		7,146		1,611		2,819		624		5,412		1,475		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 ~~refer to~~included VAT for ~~€742~~€475 million, of which ~~€557~~€315 million are current, and ~~related to~~ advances made in December (€~~608~~742 million at December 31, ~~2018,~~2019, of which ~~€383~~€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, ~~of €174~~whose underlying current portion Eni plans to recover within the next 12 months for €53 million, and beyond 12 months for €651 million (€26174 million at December 31, ~~2018)~~2019); in ~~2019~~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 ~~within~~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 ~~(€9 million at~~(same amount as of December 31, ~~2018)~~2019).

Contract liabilities included: (i) advances denominated in local currency of ~~€1,228~~€546 million (€~~716~~1,228 million at December 31, ~~2018)~~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;~~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 ~~€64~~€62 million (€6664 million at December 31, ~~2018)~~2019); the non-current portion amounted to ~~€455~~€393 million (€~~518~~455 million at December 31, ~~2018)~~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 ~~€917~~€559 million (€~~1,004~~917 million at December 31, ~~2018)~~2019).

~~Liabilities related to other current taxes include excise duties~~Other non-current liabilities included: (i) liabilities for prepaid revenues and ~~consumer taxes~~income for ~~€628~~€323 million (€~~636~~420 million at December 31, ~~2018)~~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 ~~VAT liabilities~~beyond 12 months for ~~€311~~€372 million (€~~359~~148 million at December 31, ~~2018).~~

~~Other non-current liabilities include~~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 ~~of €231 million~~ (€~~233~~231 million at December 31, ~~2018)~~2019).

Transactions with related parties are described in note 36 — Transactions with related parties.

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Initial recognition and ~~changes~~change in estimates include the increase in the asset retirement cost of Exploration & Production ~~tangible assets~~segment mainly due to the ~~decrease~~reduction in discount rates and in estimated costs for social projects to be incurred in respect to the ~~discount rate curve~~commitments being formalized between Eni SpA and ~~new obligations recorded during~~ the ~~year.~~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 ~~€4,560~~€1,690 million to ~~progress in~~ the ~~development~~commissioning of ~~reserves~~wells, plants and machinery primarily in Egypt, ~~Mexico, Libya, Ghana~~Italy, Algeria, Iraq, United States, Kazakhstan and ~~Angola.~~Mexico.

~~Changes in exploration~~Exploration and appraisal activities ~~related to: (i) the successful completion~~ of ~~exploration and appraisal activities at certain suspended exploration wells and their transfer to tangible assets for €46 million, primarily in Egypt and Angola; (ii) write-off~~2020 comprised write-offs of unsuccessful exploration wells costs for ~~€183~~€296 million mainly in ~~Australia, Kazakhstan, Pakistan, China~~Libya, United States, Angola, Egypt, Oman, Mexico and ~~United Kingdom.~~Lebanon.

Exploration and appraisal activities related for ~~€1,246~~€1,268 million to the costs of suspended exploration wells pending final determination and for ~~€317~~€66 million to costs of exploration wells in progress at the end of the year. Changes relating to suspended wells are ~~showed:~~reported below:

(€ million)	2019		2018		2017		2020		2019		2018
Costs for exploratory wells suspended – beginning of the year		1,101		1,263		1,684		1,246		1,101		1,263
Increases for which is ongoing the determination of proved reserves		368		235		451		408		368		235
Amounts previously capitalized and expensed in the year		(183)		(61)		(217)		(226)		(183)		(61)
Reclassification to successful exploratory wells following the estimation of proved reserves		(46)		(297)		(278)		(48)		(46)		(297)
Disposals		(15)		(6)		(199)				(15)		(6)
Changes in the scope of consolidation				(58)								(58)
Reclassification to assets held for sale				(24)								(24)
Currency translation differences		21		49		(178)		(112)		21		49
Costs for exploratory wells suspended – end of the year		1,246		1,101		1,263		1,268		1,246		1,101

The following information relates to the stratification of the suspended wells pending final determination (ageing):

2019 2018 2017
(€ 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 185 7.7 111 7.0 222 8.0
- between 1 and 3 years 171 6.4 87 2.9 241 3.9
- beyond 3 years 890 26.4 903 24.2 800 21.4
1,246 40.5 1,101 34.1 1,263 33.3
Costs capitalized for suspended wells
- fields including wells drilled over the last 12 months 185 7.7 111 7.0 148 5.9
- fields for which the delineation campaign is in progress 556 11.3 217 4.7 261 4.7
- fields including commercial discoveries that proceeds to sanctioning 505 21.5 773 22.4 854 22.7
1,246 40.5 1,101 34.1 1,263 33.3

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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		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		769		921		77		103		77		29		502		2,478
Additions								97		135		1		23		256								97		135		1		23		256
Net (impairments) reversals		(533)				65		(27)								(495)		(533)				65		(27)								(495)
Reclassification to proved mineral interest						(4)		(14)		(99)		(12)				(129)						(4)		(14)		(99)		(12)				(129)
Currency translation differences		17		18		1		3		2		1		10		52		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		253		939		139		162		115		19		535		2,162
2018
Book amount at the beginning of the year		1,162		825		192		99		105		7				2,390
Additions		26		56								23		487		592
Net (impairments) reversals		(429)				(76)										(505)
Reclassification to proved mineral interest		(32)				(44)				(32)		(2)				(110)
Other changes and currency translation differences		42		40		5		4		4		1		15		111
Book amount at the end of the year		769		921		77		103		77		29		502		2,478

Unproved mineral interests comprised ~~a property denominated~~the Oil Prospecting License 245 ~~(OPL 245)~~property (“OPL 245”), offshore Nigeria, ~~with a net book value of €874~~for €800 million corresponding to the price paid in 2011 to the Nigerian Government to acquire a 50% interest in the property, ~~together~~ with ~~the partner Shell which acquired~~another international oil company acquiring the remaining 50%. As of December 31, ~~2019,~~2020, the net book value of the property amounted to ~~€1,184~~€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 by Eni and Shell. Those proceedings are~~license. This proceeding is disclosed in note 27 — Guarantees, Commitments and ~~Risks.~~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 ~~also considering a stress test assuming possible delays in the start~~ of ~~development activities.~~its asset.

Accumulated provisions for impairments amounted to ~~€18,226~~€20,343 million (€~~16,471~~18,226 million at December 31, ~~2018)~~2019).

Property, plant and equipment include assets subject to operating leases for ~~€241 million.~~€358 million, essentially relating to service stations of the Refining & Marketing business line.

At December 31, ~~2019,~~2020, Eni pledged property, plant and equipment for €24 million to guarantee payments of excise duties (same amount as of December 31, ~~2018)~~2019).

Government grants recorded as a decrease of property, plant and equipment amounted to ~~€112~~€103 million (€~~125~~112 million at December 31, ~~2018)~~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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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 ~~€1,976~~€1,652 million (€1,976 million at December 31, 2019) to the portion of the liabilities attributable to ~~the~~ 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 ~~€877~~€869 million; (ii) cash payments for the interest portion of ~~€347 million; (iii) prepayment RoU for leased~~€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 ~~for €16 million.~~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)~~	~~2019~~
~~Other income and revenues~~
~~Income from remeasurement of lease liabilitiy~~		6
		6
~~Purchases, services and other~~
~~Short-term leases~~		~~115~~
~~Low-value leases~~		39
~~Variable lease payments not included in the measurement of lease liabilities~~		16
~~Capitalised direct cost associated with self-constructed assets – tangible assets~~		(2)
		~~168~~
~~Depreciation and impairments~~
~~Depreciation of RoU leased assets~~		~~999~~
~~Capitalised direct cost associated with self-constructed assets – tangible assets~~		~~(210~~)
~~Impairment losses of RoU leased assets~~		41
		~~830~~
~~Finance income (expense) from leases~~
~~Interests on lease liabilities~~		~~(378~~)
~~Capitalised finance expense of ROU leased assets – tangible assets~~		17
~~Net currency translation differences on lease liabilities~~		(6)
		~~(367~~)

~~13 Intangible assets~~

(€ million) Exploration
rights Industrial
patents and
intellectual
property rights Other
intangible
assets Intangible
assets with
finite useful
lives Goodwill Total
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
2018
Net carrying amount – beginning of the year 995 240 486 1,721 1,204 2,925
Changes in accounting policies (IFRS 15) 87 87 87
Net carrying amount restated – beginning of the year 995 240 573 1,808 1,204 3,012
Additions 133 28 180 341 341
Amortization (71) (87) (226)
(384)

(384)

Impairments (16)
(16)

(16)

Write-off (15) (1)
(16)

(16)

Currency translation differences 39 39 8 47
Change in the scope of consolidation 74 74 46 120
Other changes 40 40 26 66
Net carrying amount at the end of the year 1,081 221 584 1,886 1,284 3,170
Gross carrying amount at the end of the year 1,686 1,534 4,188 7,408
Provisions for amortization and impairment 605 1,313 3,604 5,522

(€ 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 ~~mainly~~ in Angola, Albania, United Arab Emirates, ~~Mozambique, Mexico~~Egypt, Oman and ~~Indonesia.~~the extension of a licence in Gabon.

The breakdown of exploration rights by type of asset was as follows:

(€ million)	December 31, 2019		December 31, 2018		December 31, 2020		December 31, 2019
Proved licence and leasehold property acquisition costs		291		357		225		291
Unproved licence and leasehold property acquisition costs		709		684		653		709
Other mineral interests		31		40		10		31
		1,031		1,081		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 ~~the retail~~Eni gas e luce business line for ~~€226~~€262 million (€~~166~~226 million at December 31, ~~2018)~~2019); (ii) concessions, licenses, trademarks and similar items for ~~€102~~€88 million (€~~151~~102 million at December 31, ~~2018)~~2019) comprised transmission rights for natural gas imported from Algeria ~~of €30~~for €25 million (€2730 million at December 31, ~~2018)~~2019); (iii) capital expenditures in progress on natural gas pipelines for which Eni has acquired transport rights for €78 million (same amount atas of December 31, ~~2018)~~2019).

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The main amortization rates used were substantially unchanged from the previous year and ranged as follows:

(%)
Exploration rights					UOP ~~– 33~~
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					2517 – 33
Other intangible assets					4 – 20

~~The carrying amount of goodwill~~Cumulative impairments charges at the end of the year amounted ~~€2,454 million, net~~to €2,457 million.

The breakdown of ~~cumulative impairments charges. The breakdown~~goodwill by segment is provided below:

(€ million)	December 31, 2019		December 31, 2018		December 31, 2020		December 31, 2019
Gas & Power		981		977
Eni gas e luce						1,046		981
Exploration & Production		190		187		146		190
Refining & Marketing and Chemicals		93		119
Other activities		1		1
Refining & Marketing						93		93
Corporate and Other activities						11
Renewables						1		1
		1,265		1,284		1,297		1,265

An impairment loss of the entire allocated goodwill was recorded by the Chemical business line in relation to activities concerning the development, industrialization, licensing of bio-chemical technologies and processes based on the use of renewable sources.

~~An increase in~~ goodwill was recorded in ~~connection with the allocation~~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 ~~cost~~ of the ~~company SEA SpA, which engages~~70% stake in ~~providing services and solutions for energy efficiency~~Evolvere, a group operating in the ~~residential and industrial segments.~~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.

~~The amount of goodwill outstanding at the reporting date mainly related~~With regard to the ~~Gas & Power segment.~~Eni gas e luce business line, which has significant allocated goodwill, the allocation of CGU was carried out as follows:

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There are no ~~realistic hypotheses~~reasonable assumptions of changes in the discount rate, growth rate, profitability or volumes that would lead to zeroing the headroom amounting to ~~€1,701~~€2,856 million of the value in use of the ~~Italian Market~~ CGU Domestic market with respect to its book value, including the allocated goodwill.

Goodwill allocated to the CGU ~~European gas~~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 ~~gas~~ market ~~CGU~~ confirmed the recoverability of the carrying amount of these ~~gas~~ market CGUs, including ~~any allocated~~the goodwill, by using a post-tax WACC adjusted considering a post-tax country risk for France of ~~5.9%,~~4.6% and ~~6.2%~~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 ~~assessing whether impairment is required,~~2021 and 2022, Brent prices are set at 50 and 55 $/bbl, respectively. The gas price of the ~~carrying amounts~~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 ~~are compared with their recoverable amounts. The recoverable amount is~~were estimated on the higher between an asset’s fair value less costs to sell and its value-in-use. In the event of an asset’s impairment being reversed, the reversal may not raise the carrying amount above the value it would have stood at taking into account depreciation, if no impairment had originally been recognized. Impairment losses of goodwill cannot be reversed.

~~Given the nature~~basis of Eni’s ~~activities, information~~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 ~~asset fair~~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 ~~is usually difficult~~of the consolidated net assets, and the company policy to ~~obtain unless negotiations with a potential buyer are ongoing. Therefore,~~regularly test the recoverability ~~is verified by estimating assets’ values-in-use. The valuation is carried out for individual assets or for~~of carrying amounts, an impairment test covering 100% of the smallest identifiable group of assets that generates cash inflows that are largely independent from the cash inflows from other assets, or groups of assets (cash generating unit — CGU). The Group has identified the following CGUs: (i) inCGUs was performed.

In the Exploration & Production ~~segment, individual oilfields~~sector, impairment losses of assets in production or ~~pools~~development were recognized for €1,888 million, mainly due to the revision of ~~oilfields when technical, economic or contractual features make underlying cash flows interdependent; (ii) in~~long-term hydrocarbons prices and the ~~Gas & Power segment, the CGUs~~reduced capital expenditures to which goodwill arisen from business combinations was allocated and costs for customer acquisition (Italian retail market and other foreign markets), electric power plants, international pipelines and other minor activities; (iii) in the Refining & Marketing business line, refining plants, and assets related to distribution channels grouped by countrydevelop reserves, as well as downward revisions of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) in the Chemical business five lines of activities have been identified as autonomous CGUs: intermediates, polyethylene, styrenes, elastomers and biotech activities.reserves. The most

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Assignificant 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 ~~2019, following~~about 6% for Italy/USA to a range of 7–8% for the ~~application~~other countries, which are redetermined in a range of ~~IFRS 16,~~6-14% pre-tax.

In the ~~book values~~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 ~~identified CGUs include~~European industry, explained by: the ~~right~~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 ~~use assets (RoU), associated~~medium/heavy crude oils, penalizing the profitability of conversion cycles. The pre-tax and post-tax discount rate relating to ~~plants~~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 ~~equipment hired in connection with operations at specific CGUs operations. Because they are instrumental~~repopulation of primary and secondary forests to ~~specific CGUs operation, those RoU assets lack the requisites to be evaluated as autonomous CGUs. The CGUs’ cash flows to which the RoUs have been allocated exclude lease liability repayments~~obtain carbon credits, certified according to international standards. Management expects a gradual ramp up of these initiatives in the ~~unlevered valuation methodology used~~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 ~~capital projects. Rather, a small number~~the purposes of ~~RoU not allocated to CGU~~carbon neutrality of equity production from 2030 onwards. The expenditures for the purchase of carbon credits are considered ~~corporate assets, whose recoverability depends on~~part of the operating costs of the Exploration & Production sector with reference to the whole sector considered as a single CGU. Net of ~~the company’s CGUs.~~

The value-in-use is calculated by discounting the estimated future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from disposal atthese projected costs until the end of their useful lives. Cash flows are determined based on the best information available at the time of the assessment. Cash flow projections for the first four years of each CGU evaluation are extracted from the Company’s four-year plan adopted by the top management. The plan includes data points on expected oil&gas production volumes, reserves, sales volumes, capital expenditure, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates. The estimation of CGUs’ terminal values is based on cash flow projections beyond the four-year plan horizon, which are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and considering the expected useful lives of the Company’s CGUs and certain assumptions regarding future trends in revenues and costs. In the case of the oil&gas CGUs, management assumed the residual life of the reserves, ~~considering~~ the ~~expected production rates and~~overall headroom of the ~~associated projections of operating costs and development expenditures. The CGUs of Refining~~Exploration & ~~Marketing, Chemical and Gas & Power, with a definite useful life, (i.e. power plants) are evaluated based~~Production sector determined on the ~~plant economic and technical life and the associated, normalized projections~~basis of operating costs and expenditures to support plant efficiency. The CGUs of the gas market business to which goodwill has been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0%. In the forecast of the operating expenses are considered expected costs to be incurred in compliance to the so-called CO2 Emission Trading Scheme applicable to CGUs operating within the EU economic space. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns.

The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair.

The oil market continues to be affected by weak fundamentals against the backdrop of an unabated supply glut, fueled by continuing grow in U.S. tight oil output and a seemingly fading commitment on part of the oil producers of the OPEC+ agreement at supporting crude oil prices going forward. The market is also weighed down by uncertainties about the strength of the global economic recovery, exposed to a wide range of systemic risks, including geopolitical risks, any possible development in the trade dispute between USA and China, the relationship between the EU and the UK post Brexit. Eni’s management forecast a gradual rebalancing of global supplies and demand for crude oil over the medium term, under the assumptions of ~~moderate economic growth and taking into account~~ the ~~stricter capital discipline adopted~~impairment test is reduced by ~~major~~4.6%.

The reasonableness of the outcome of the impairment review made by Eni at its oil ~~companies designed to curtail growth plans to boost shareholders’ returns and lately~~&gas activities was assessed on the basis of a ~~shift~~stress test analysis performed using the decarbonization scenario developed by the International Energy Agency (IEA) in its Sustainable Development Scenario in the ~~financial approach retained~~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 ~~U.S. independent producers which have de-emphasized growth~~IEA of hydrocarbon prices and the purchase cost of emission allowances of the “advanced” economies equal to preserve the free cash flow. Based on these considerations and taking into account the forecasts made by specialized observatories and investment banks, management has retained its assumption of a long-term Brent crude oil$140 in 2040 in 2019 currency per ton. IEA price ~~of 70 $/BBL in real terms 2022,~~assumptions for hydrocarbons are substantially in line with those adopted by Eni, while the ~~assumption made~~cost of CO2 is significantly higher. This stress test indicates a loss in the ~~annual report 2018.~~

~~The oversupply condition is even more severe in the gas market due to excess production~~value-in-use of associated gas in the USA and to the ramp-up of several liquefaction projects which have significantly increased global supplies of LNG at a time when the greatest consuming countries have slowed down (China, South Korea and Japan). Management expect gas prices to rebalance in the medium term considering an anticipated recovery of the Asian economies and also considering an ongoing switch from coal to gas in the power generation in Europe. Overall, price assumptions for the main gas benchmarks in Europe have been retained at the same level as the previous planning projections, whilst gas prices assumptions have been revised downward for the reference Henry Hub gas prices in USA due to structural headwinds.

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15 Investments

Equity-accounted investments

	2019								2018								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		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		95		5,497		1,452		7,044		116		2,332		1,063		3,511		86		4,592		4,357		9,035		95		5,497		1,452		7,044
Changes in accounting policies (IFRS 9 and 15)												(34)		(3)		(37)
Changes in accounting policies (IAS 28)				22				22																				22				22
Carrying amount restated – beginning of the year		95		5,519		1,452		7,066		116		2,298		1,060		3,474		86		4,592		4,357		9,035		95		5,519		1,452		7,066
Additions and subscriptions		6		76		2,910		2,992				28		92		120		2		75		198		275		6		76		2,910		2,992
Divestments and reimbursements		(5)				(17)		(22)		(33)		(3)		(115)		(151)				(3)		(1)		(4)		(5)				(17)		(22)
Share of profit of equity-accounted investments		6		80		75		161		8		16		385		409		3		21		14		38		6		80		75		161
Share of loss of equity-accounted investments		(10)		(157)		(17)		(184)		(5)		(415)		(10)		(430)		(2)		(1,399)		(332)		(1,733)		(10)		(157)		(17)		(184)
Deduction for dividends		(4)		(1,073)		(61)		(1,138)		(6)		(19)		(25)		(50)		(5)		(296)		(13)		(314)		(4)		(1,073)		(61)		(1,138)
Change in the scope of consolidation		1						1				3,448				3,448		3		30		1		34		1						1
Currency translation differences		2		67		17		86		2		25		54		81		(4)		(254)		(345)		(603)		2		67		17		86
Other changes		(5)		80		(2)		73		13		119		11		143		(3)		66		(42)		21		(5)		80		(2)		73
Carrying amount – end of the year		86		4,592		4,357		9,035		95		5,497		1,452		7,044		80		2,832		3,837		6,749		86		4,592		4,357		9,035

~~In 2019 additions~~Acquisitions and ~~subscriptions related to:~~share capital increases mainly related: (i) for €89 million to the acquisition of a ~~20% equity interest~~49% stake in ~~Abu Dhabi Oil Refining Co (Takreer), UAE acquired~~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 ~~cash consideration~~40% stake of ~~€2,896 million. The investee operates three refineries~~Finproject SpA, a company operating in ~~Ruwais (Ruwais East and Ruwais West) and Abu Dhabi, with a refining capacity in excess of 900 KBBL per day. With this transaction, Eni enters~~ the ~~UAE downstream~~compounding sector and ~~increases its global refining capacity by 35%,~~ in ~~line with~~ the ~~Company’s strategy~~production of ~~making Eni’s overall portfolio~~ultralight fabrics, businesses more ~~geographically diversified and more balanced along~~resilient to the ~~value chain; (ii)~~volatility of the chemicals market; (iii) for €38 million to a capital contribution ~~of €39 million~~ made to Lotte Versalis Elastomers Co Ltd, a joint venture operating in ~~production~~the manufacturing of elastomers in South Korea.

~~Share of profit of equity-accounted investments included a gain of €49 million related to Vår Energi AS and of €47 million to Angola LNG Ltd.~~

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 ~~resulted in~~for €354 million due to a ~~gain of €4 million. Considering~~weaker scenario, which impacted the ~~volatility of the Saipem shares and the ongoing uncertainties surrounding a recovery in the investing cycle~~investment decisions of oil companies together with the curtailments of expenditures made during the downturn driving, lower demand for oil and ~~competitive pressure~~gas services as well as the recognition of impairment losses in particular in the Engineering & Construction segment, management performed an impairment review of the investment to assess its recoverability based on an internal financial model of future cash flows of Saipem. Inputs to that model were estimated based on financial projections made by the sell-side analysts who cover the Saipem shares, publicly available data on Saipem and the observed historical correlation which link the Saipem turnover to crude oil prices and spending in capital projects made by oil companies. This review supported the book value of the investment.Offshore Drilling CGU.

Share of losses of equity-accounted investments included a loss of ~~€90~~€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 ~~1,057~~€274 million to Vår Energi AS.

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Net carrying amount related to the following companies:

December 31, 2019 December 31, 2018
(€ million) Net carrying
amount % of the
investment Net carrying
amount % of the
investment
Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd 30 100.00 31 100.00
Other (*) 56 64
86 95
Joint ventures
Vår Energi AS 2,518 69.60 3,498 69.60
Saipem SpA 1,250 30.99 1,228 30.99
Unión Fenosa Gas SA 326 50.00 335 50.00
Cardón IV SA 148 50.00 98 50.00
Gas Distribution Company of Thessaloniki – Thessaly SA 139 49.00 137 49.00
Lotte Versalis Elastomers Co Ltd 74 50.00 75 50.00
PetroJunín SA 53 40.00 47 40.00
AET – Raffineriebeteiligungsgesellschaft mbH 35 33.33 32 33.33
Other (*) 49 47
4,592 5,497
Associates
Abu Dhabi Oil Refining Co (Takreer) 2,829 20.00
Angola LNG Ltd 1,159 13.60 1,106 13.60
Coral FLNG SA 102 25.00 102 25.00
Novamont SpA 71 25.00 67 25.00
United Gas Derivatives Co 69 33.33 62 33.33
Commonwealth Fusion Systems Llc(a)
37 42
Other (*) 90 73
4,357 1,452
9,035 7,044

~~(a)~~

~~The ownership cannot be determined.~~

~~(*)~~

~~Each individual amount included herein was lower than €25 million.~~

As of December 31, 2019, the book value of investments included Vår Energi SA which was established at the end of 2018 following the merger between the former Eni subsidiary Eni Norge AS and Point Resources AS for maximizing synergies in the development of hydrocarbon reserves in Norway through the sharing of assets and know-how. The decrease of €980 million compared to the opening balance was due to the distribution of dividends classified as part of the cash flow from operating activities considering that Vår Energi SA is an investment integrated in the industrial plans and the upstream growth strategy of Eni. This decrease was partially absorbed by Eni’s share of profit.

	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 ~~€72~~€44 million ~~related~~relating to ~~Novamont SpA for €43 million and Unión Fenosa Gas SA for €29 million. These surpluses were~~Finproject SpA. This surplus was driven by the long-term profitability outlook of the acquired ~~companies~~company at the time of the acquisition.

As of December 31, ~~2019,~~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		~~30.99~~31.08
Share price (€)		~~4.356~~2.205
Market value (€(€ million)		~~1,345~~681
Book value (€(€ million)		~~1,250~~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.

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Additional information is included in note 37 — Other information about investments.

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Other investments

(€ million)	2019		2018		2020		2019
Carrying amount – beginning of the year		919		219		929		919
Changes in accounting policies (IFRS 9)				681
Carrying amount restated – beginning of the year		919		900
Additions and subscriptions		11		5		8		11
Change in the fair value		(3)		15		24		(3)
Divestments and reimbursements		(12)		(22)		(12)		(12)
Currency translation differences		15		31		(61)		15
Other changes		(1)		(10)		69		(1)
Carrying amount – end of the year		929		919		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, ~~2019~~2020 primarily related to Nigeria LNG Ltd for ~~€657~~€579 million (€~~651~~657 million at December 31, ~~2018) and~~2019), Saudi European Petrochemical Co “IBN ZAHR” for ~~€146~~€115 million (€~~144~~146 million at December 31, ~~2018).~~2019) and Novamont SpA for €77 million.

16 Other financial assets

	December 31, 2019				December 31, 2018				December 31, 2020				December 31, 2019
(€ million)	Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current
Long-term financing receivables held for operating purposes		60		1,119		61		1,189		29		953		60		1,119
Short-term financing receivables held for operating purposes		37				51				22				37
		97		1,119		112		1,189		51		953		97		1,119
Financing receivables held for non-operating purposes		287				188				203				287
		384		1,119		300		1,189		254		953		384		1,119
Securities held for operating purposes				55				64				55				55
		384		1,174		300		1,253		254		1,008		384		1,174

~~Financing receivables are stated net of~~Changes in allowance for doubtful accounts were as follows:

(€ million)	2019		2018		2020		2019
Carrying amount at the beginning of the year		430		730		379		430
Additions		11		279		7		11
Deductions		(88)		(596)		(7)		(88)
Currency translation differences		7		17		(26)		7
Other changes		19				(1)		19
Carrying amount at the end of the year		379		430		352		379

Financing receivables held for operating purposes related principally to funds provided to joint ventures and associates in the Exploration & Production segment (€~~1,041 million) and the Gas & Power segment (€49~~883 million) to execute capital projects of interest to Eni. These receivables are ~~expression of~~

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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 ~~€563~~€383 million (€563 million at December 31, ~~2019 (€705 million at December 31, 2018)~~2019).

Financing receivables held for operating purposes due beyond five years amounted to ~~€1,018~~€771 million (€~~1,088~~1,018 million at December 31, ~~2018)~~2019).

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The fair value of non-current financing receivables held for operating purposes of ~~€1,119~~€953 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from ~~-0.3%~~-0.5% to ~~2.0% (-0.2%~~1.4% (-0.3% and ~~2.9%~~2.0% at December 31, ~~2018)~~2019).

~~The~~In addition to the expected credit loss model, the recoverability of the financial loan granted to the joint venture Cardón IV SA ~~to fund the development projects carried out by the venture~~ was assessed ~~based~~ on the ~~future, expected cash flows~~basis of the industrial project. These cash flows are exposed to a counterparty risk given the difficult financial condition of Venezuela and of the national oil company, PDVSA, and to the complexity of the local operating environment. To factor in those risks in assessing the recoverability of the ~~financing,~~investment made by the JV for the development of the Perla field corresponding to the future cash flows of the project ~~have been~~ adjusted to price possible difficulties in converting future gas sales into cash, essentially assuming a deferral in the ~~time~~timing of revenues collection. This schedule was estimated on the basis of a study on empirical evidence relating to the average recovery rates obtained by creditors in the context of sovereign defaults, adjusted to reflect the strategic role of the energy sector to local economy. Those risked cash flows have been then discounted to a risk-adjusted WACC which incorporates the deteriorated local operating environment. This recoverability assessment confirmed the book value of the financial receivable. The same method was used to estimate the recoverable amount of the overdue trade receivables for gas supplies to the state-owned company PDVSA. In 2019, the percentages of the gas revenues collected by the joint venture were in line with the estimates adopted in assessing the loss-given-default applied in the evaluation recoverability performed in 2018; therefore, no adjustment was necessary to the estimation of the percentage of recoverability of these receivables.

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 ~~€370~~€178 million and ~~€1,112~~€1,024 million, respectively.

Securities held for operating purposes related to listed bonds issued by sovereign states.

Securities for €20 million (same amount atas of December 31, ~~2018)~~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	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		24		24		25	from 0.20 to 4.75	from 2020 to 2025	Baa3	BBB		24		24		25	from 0.35 to 4.75	from 2021 to 2030	Baa3	BBB
Others (*)		23		23		23	from 0.05 to 4.20	from 2020 to 2024	from Aa3 to Baa1	from AA to A-		17		17		17	from 0.05 to 0.20	from 2021 to 2025	from Aa3 to Baa1	from AA to A
Floating rate bonds
Italy		5		5		5		from 2020 to 2022	Baa3	BBB		11		11		11		from 2022 to 2025	Baa3	BBB
Others		3		3		3		2022	Baa3	BBB		3		3		3		2022	Baa3	BBB
Total sovereign states		55		55		56						55		55		56

(*)

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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~~17 Trade and other~~The decrease in trade payables of €1,801 million was mainly due to lower prices of hydrocarbons.

~~The following are~~Other payables included: (i) the ~~effects~~amounts to be paid due to the triggering of the ~~application~~take-or-pay clause of ~~IFRS 16:~~

(€ million) Trade
payables Down payments
and advances from
joint ventures in
exploration and
production
activities Other
payables Total trade
and other
payables
Carrying amount at December 31, 2018 11,645 207 4,895 16,747
Changes in accounting policies (IFRS 16) (128) (128)
Carrying amount at January 1, 2019 11,517 207 4,895 16,619

~~The first application~~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 ~~IFRS 16 is disclosed in note 3 — Changes in accounting policies.~~December 31, 2019).

~~The breakdown of trade and other payables is the following:~~

(€ million) December 31,2019 December 31,2018
Trade payables 10,480 11,645
Down payments and advances from joint ventures in exploration & production activities 401 207
Payables for purchase of non-current assets 2,276 2,530
Payables due to joint ventures in exploration & production activities 1,236 1,151
Other payables 1,152 1,214
15,545 16,747

Trade and other payables were denominated in euro for ~~€5,866~~€5,384 million and in U.S. dollar for ~~€8,371~~€6,243 million.

Because of the short-term maturity and conditions of remuneration of trade ~~and other~~ payables, the fair values approximated the carrying amounts.

~~Payables~~Trade and other payables due to related parties are described in note 36 — Transactions with related parties.

18 Finance debts

	December 31, 2019								December 31, 2018								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		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		187		504		2,341		3,032		383		768		2,710		3,861		337		759		3,193		4,289		187		504		2,341		3,032
Ordinary bonds				2,642		16,137		18,779				2,781		16,923		19,704				1,140		18,280		19,420				2,642		16,137		18,779
Convertible bonds						393		393						390		390						396		396						393		393
Commercial papers		1,778						1,778		915						915		2,233						2,233		1,778						1,778
Other financial institutions		487		10		39		536		884		52		59		995		312		10		26		348		487		10		39		536
		2,452		3,156		18,910		24,518		2,182		3,601		20,082		25,865		2,882		1,909		21,895		26,686		2,452		3,156		18,910		24,518

Finance debts ~~decreased of €1,347~~increased by €2,168 million due to ~~repayments made~~new issuance, net of ~~new issuance~~repayments of ~~€1,540~~€3,115 million, ~~and increased due to~~partially offset by currency translation differences relating to foreign subsidiaries and ~~debt~~debts denominated in foreign currency recorded by euro-reporting subsidiaries for ~~€249~~€876 million.

Commercial papers were issued by the Group’s financial subsidiaries.

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~~The following table reflects long-term debt as of December 31, 2019 by maturity:~~

Long-term debt
(€ million) 2021 2022 2023 2024 After Total
Banks 750 146 838 134 473 2,341
Ordinary bonds 930 698 1,879 1,641 10,989 16,137
Convertible bonds 393 393
Other financial institutions 11 13 14 1 39
1,691 1,250 2,731 1,776 11,462 18,910

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. In addition, Eni entered into long-term facilities subject to the retention of certain financial ratios based on the Consolidated Financial Statements of Eni with Citibank Europe Plc. In case of default, the bank may request early repayment. At December 31, ~~2019,~~2020, debts subjected to restrictive covenants amounted to ~~€1,243~~€1,051 million (€~~1,337~~1,243 million at December 31, ~~2018)~~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 ~~€15,030~~€16,356 million and other bonds for a total of ~~€3,749~~€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, ~~2019:~~2020:

(€ million)	Amount		Discount on bond issue and accrued expense		Total		Currency		Maturity				Rate %				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		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		1,200		16		1,216		EUR				2025				3.750		1,000		28		1,028		EUR				2029				3.625
Eni SpA		1,000		38		1,038		EUR				2020				4.250		1,000		12		1,012		EUR				2023				3.250
Eni SpA		1,000		28		1,028		EUR				2029				3.625		1,000		10		1,010		EUR				2031				2.000
Eni SpA		1,000		20		1,020		EUR				2020				4.000		1,000		9		1,009		EUR				2026				1.500
Eni SpA		1,000		10		1,010		EUR				2023				3.250		1,000		2		1,002		EUR				2030				0.625
Eni SpA		1,000		8		1,008		EUR				2026				1.500		1,000				1,000		EUR				2026				1.250
Eni SpA		900		(4)		896		EUR				2024				0.625		900		(2)		898		EUR				2024				0.625
Eni SpA		800		2		802		EUR				2021				2.625		800		2		802		EUR				2021				2.625
Eni SpA		800		(1)		799		EUR				2028				1.625		800		1		801		EUR				2028				1.625
Eni SpA		750		9		759		EUR				2024				1.750		750		10		760		EUR				2024				1.750
Eni SpA		750		5		755		EUR				2027				1.500		750		6		756		EUR				2027				1.500
Eni SpA		750		(4)		746		EUR				2034				1.000		750		(4)		746		EUR				2034				1.000
Eni SpA		700		2		702		EUR				2022				0.750		700		2		702		EUR				2022				0.750
Eni SpA		650		3		653		EUR				2025				1.000		650		3		653		EUR				2025				1.000
Eni SpA		600		(4)		596		EUR				2028				1.125		600		(4)		596		EUR				2028				1.125
Eni Finance International SA		1,558		(3)		1,555		USD		2026		2027				variable		1,427		(3)		1,424		USD		2026		2027				variable
Eni Finance International SA		295		4		299		EUR		2028		2043		3.875		5.441		795		6		801		EUR		2025		2043		1.275		5.441
Eni Finance International SA		118		5		123		GBP				2021				4.750		111		5		116		GBP				2021				4.750
Eni Finance International SA		25				25		YEN				2021				1.955		24				24		YEN				2021				1.955
		14,896		134		15,030												16,257		99		16,356
Other bonds
Eni SpA		890		4		894		USD				2023				4.000		815		5		820		USD				2023				4.000
Eni SpA		890		2		892		USD				2028				4.750		815		3		818		USD				2028				4.750
Eni SpA		890		(1)		889		USD				2029				4.250		815		(1)		814		USD				2029				4.250
Eni SpA		401		4		405		USD				2020				4.150		285		1		286		USD				2040				5.700
Eni SpA		312		1		313		USD				2040				5.700
Eni USA Inc		356				356		USD				2027				7.300		326				326		USD				2027				7.300
		3,739		10		3,749												3,056		8		3,064
		18,635		144		18,779												19,313		107		19,420

As of December 31, ~~2019,~~2020, ordinary bonds maturing within 18 months amounted to ~~€2,611~~€1,644 million. During ~~2019,~~2020, new bonds issued amounted to ~~€1,635~~€3,514 million.

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The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, ~~2019:~~2020:

(€ million)

Amount

Discount on
bond issue
and accrued
expense

Total

Currency

Maturity

Rate %

Amount

Discount on
bond issue
and accrued
expense

Total

Currency

Maturity

Rate %

Eni SpA

400

(7)

393

EUR

2022

0.000

400

(4)

396

EUR

2022

0.000

~~The~~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 ~~have “conversion”~~can exercise their conversion rights at certain ~~times~~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 ~~€14.9~~€16.3 billion were drawn as of December 31, ~~2019.~~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, 2019								December 31, 2018								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 (%)		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		464		0.2		16,526		2.1		680		1.9		18,635		2.3		1,004				19,142		1.7		464		0.2		16,526		2.1
U.S. dollar		1,981		2.3		5,392		4.6		1,007		2.5		4,530		4.3		1,870		1.1		4,522		4.6		1,981		2.3		5,392		4.6
Other currencies		7		(0.7)		148		4.3		495		1.0		518		4.2		8		(0.5)		140		4.3		7		(0.7)		148		4.3
		2,452				22,066				2,182				23,683				2,882				23,804				2,452				22,066

As of December 31, ~~2019,~~2020, Eni retained undrawn uncommitted short-term borrowing facilities amounting to ~~€13,299~~€7,183 million (€~~12,484~~13,299 million at December 31, ~~2018)~~2019) and undrawn ~~long-term~~ committed borrowing facilities of ~~€4,667~~€5,295 million, of which €4,750 million due beyond 12 months (€~~5,214~~4,667 million at December 31, ~~2018)~~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, ~~2019,~~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)	December 31, 2019		December 31, 2018
Ordinary bonds		19,173		20,257		22,429		19,173
Convertible bonds		402		399		497		402
Banks		2,904		3,445		4,008		2,904
Other financial institutions		49		111		36		49
		22,528		24,212		26,970		22,528

Fair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from ~~-0.3%~~-0.5% to ~~2.0% (-0.2%~~1.4% (-0.3% and ~~2.9%~~2.0% at December 31, ~~2018)~~2019).

Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.

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Changes in liabilities arising from financing activities

(€ million) Long-term debt
and current
portion of
long-term debt Short-term
debt Long-term
and current
portion of
long-term
lease liabilietis Total
Carrying amount at December 31, 2018 23,683 2,182 25,865
First adoption IFRS 16 5,656 5,656
Reclassifications 168 168
Reclassification to liabilities directly associated with assets held for sale (13) (13)
Carrying amount at January 1, 2019 23,683 2,182 5,811 31,676
Cash flows (1,701) 161 (877) (2,417)
Currency translation differences 157 92 93 342
Changes in the scope of consolidation 5 5
Other non-monetary changes (73) 12 621 560
Carrying amount at December 31, 2019 22,066 2,452 5,648 30,166

(€ 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 ~~€668~~€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~~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.

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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, 2019 December 31, 2018
(€ million) Current Non-current Total Current Non-current Total
A. Cash and cash equivalents 5,994 5,994 10,836 10,836
B. Held-for-trading financial assets 6,760 6,760 6,552 6,552
C Liquidity (A+B) 12,754 12,754 17,388 17,388
D. Financing receivables 287 287 188 188
E. Short-term debt towards banks 187 187 383 383
F. Long-term debt towards banks 504 2,341 2,845 768 2,710 3,478
G. Bonds 2,642 16,530 19,172 2,781 �� 17,313 20,094
H. Short-term debt towards related parties 46 46 661 661
I. Other short-term liabilities 2,219 2,219 1,138 1,138
J. Other long-term liabilities 10 39 49 52 59 111
K. Total borrowings before lease liabilities (E+F+G+H+I+J) 5,608 18,910 24,518 5,783 20,082 25,865
L. Net borrowings before lease liabilities (K-C-D) (7,433) 18,910 11,477 (11,793) 20,082 8,289
M. Lease liabilities 884 4,751 5,635
N. Lease liabilities towards related parties 5 8 13
O. Total borrowings including lease liabilities (K+M+N) 6,497 23,669 30,166 5,783 20,082 25,865
P. Net borrowings including lease liabilities (O-C-D) (6,544) 23,669 17,125 (11,793) 20,082 8,289

	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.

~~Liabilities for leased assets~~Lease liabilities related for ~~€1,976~~€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

(€ 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, 2018 6,777 2,595 824 180 327 204 130 108 66 415 11,626
New or increased provisions 354 165 38 173 65 2 2 411 1,210
Initial recognition and changes in
estimates 2,074 2,074
Accretion discount 247 7 (2) 3 255
Reversal of utilized provisions (313) (299) (43) (24) (175) (11) (12) (51)
(928)

Reversal of unutilized provisions (7) (25) (105) (19) (29) (10) (7)
(202)

Currency translation differences 112 13 8 2 4 139
Other changes 46 (30) (2) (3) 8 (83) 2 (6)
(68)

Carrying amount at
December 31, 2019 8,936 2,602 850 199 333 188 113 70 46 769 14,106

Provisions for site restoration, abandonment and social projects include the present value of the estimated costs that the Company expects to incur for ~~decommissioning~~dismantling oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, ~~abandonment~~site clean-up and ~~site~~ restoration ~~of the~~

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~~Exploration & Production segment~~ for ~~€8,411~~€8,454 million. Initial recognitions and changes in estimates of ~~€2,074~~€955 million were ~~mainly~~ driven by a decrease in the discount ~~rate curve~~rates and the estimate of the costs for social projects to ~~a lesser extent by~~be incurred following the ~~recognition of new decommissioning obligations due~~commitments between Eni SpA and the Basilicata region in relation to the ~~activity of~~oil development program in the ~~year.~~Val d’Agri concession area (€439 million). The unwinding of discount recognized through profit and loss for ~~€247~~€190 million was determined based on discount rates ranging from ~~-0.1%~~-0.2% to ~~6.1%~~3.7% (from ~~-0.2%~~-0.1% to 6.1% at December 31, ~~2018)~~2019). Main expenditures associated with decommissioning operations are expected to be incurred over a ~~45-year~~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, ~~2019,~~2020, environmental provision primarily related to Eni Rewind SpA ~~(former Syndial SpA)~~ for ~~€1,930~~€1,647 million and to the Refining & Marketing business line for €416 million which includes the costs of restoration and environmental remediation as a part of the Memorandum of Understanding signed between Eni and the Ministry for the Environment in December 2019.€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 ~~€723~~€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 ~~other than income taxes~~matters related to the estimated losses that the Company expects to incur to settle ~~uncertain~~ tax ~~matters~~litigations and tax claims pending with tax authorities in relation to uncertainties in applying rules in force ~~for foreign subsidiaries~~were in respect of the Exploration & Production segment for ~~€169~~€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 ~~€162~~€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 ~~€131~~€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, 2019 December 31, 2018
Italian defined benefit plans 269 275
Foreign defined benefit plans 412 385
FISDE, foreign medical plans and other 177 148
Defined benefit plans 858 808
Other benefit plans 278 309
Provision for employee benefits 1,136 1,117

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(€ 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 basis of~~ the contributions paid by the Company.

Other employee benefit plans related to deferred monetary incentive plans for ~~€132~~€128 million, the isopensione plans (a post retirement benefit plan applicable to a specific category of employees) of Eni gas e luce SpA for ~~€107~~€97 million, jubilee awards for ~~€25~~€28 million and other long-term plans for ~~€14~~€15 million.

Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

2019 2018
(€ 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 275 925 148 1,348 309 1,657 284 997 135 1,416 194 1,610
Current cost 19 2 21 55 76 27 2 29 42 71
Interest cost 4 37 3 44 1 45 4 31 2 37 1 38
Remeasurements: 5 41 24 70 1 71 1 (25) 13
(11)
30 19
- actuarial (gains) losses due to changes in financial assumptions 7 50 3 60 1 61 (31) 1
(30)
29
(1)

- experience (gains) losses (2) (9) 21 10 10 1 6 12 19 1 20
Past service cost and (gains) losses settlements 1 8 9 (2) 7 2 1 3 115 118
Plan contributions: 1 1 1 1 1 1
- employee contributions 1 1 1 1 1 1
Benefits paid (15) (28) (9)
(52)
(88)
(140)
(15) (35) (9)
(59)
(74)
(133)

Reclassification to liabilities directly associated with asset held for sale (8)
(8)

(8)

Changes in the scope of consolidation (90)
(90)
(2)
(92)

Currency translation differences and other changes 48 1 49 2 51 1 25 4 30 3 33
Present value of benefit liabilities at end of year (a) 269 1,044 177 1,490 278 1,768 275 925 148 1,348 309 1,657
Plan assets at beginning of year 545 545 545 588 588 588
Interest income 20 20 20 17 17 17
Return on plan assets 23 23 23
(21)
(21) (21)
Plan contributions: 14 14 14 25 25 25
- employee contributions 1 1 1 1 1 1
- employer contributions 13 13 13 24 24 24
Benefits paid
(19)
(19) (19)
(26)
(26) (26)
Changes in the scope of consolidation (64)
(64)

(64)

Currency translation differences and other changes 49 49 49 26 26 26
Plan assets at end of year (b) 632 632 632 545 545 545
Asset ceiling at beginning of year 5 5 5
Change in asset ceiling
(5)
(5) (5) 5 5 5
Asset ceiling at end of year (c) 5 5 5
Net liability recognized at end of year
(a-b+c) 269 412 177 858 278 1,136 275 385 148 808 309 1,117

	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 ~~€175~~€268 million (€~~181~~175 million at December 31, ~~2018)~~2019). Eni recorded a receivable for an amount equivalent to such liability.

~~F-67~~

~~TABLE OF CONTENTS~~

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		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				19		2		21		55		76
Past service cost and (gains) losses on settlements				1		8		9		(2)		7				1		8		9		(2)		7
Interest cost (income), net:
- interest cost on liabilities		4		37		3		44		1		45		4		37		3		44		1		45
- interest income on plan assets				(20)				(20)				(20)				(20)				(20)				(20)
Total interest cost (income), net		4		17		3		24		1		25		4		17		3		24		1		25
- of which recognized in “Payroll and related cost”										1		1										1		1
- of which recognized in “Financial income (expense)”		4		17		3		24				24		4		17		3		24				24
Remeasurements for long-term plans										1		1										1		1
Total		4		37		13		54		55		109		4		37		13		54		55		109
- of which recognized in “Payroll and related cost”				20		10		30		55		85				20		10		30		55		85
- of which recognized in “Financial income (expense)”		4		17		3		24				24		4		17		3		24				24
2018
Current cost				27		2		29		42		71
Past service cost and (gains) losses on settlements				2		1		3		115		118
Interest cost (income), net:
- interest cost on liabilities		4		31		2		37		1		38
- interest income on plan assets				(17)				(17)				(17)
Total interest cost (income), net		4		14		2		20		1		21
- of which recognized in “Payroll and related cost”										1		1
- of which recognized in “Financial income (expense)”		4		14		2		20				20
Remeasurements for long-term plans										30		30
Total		4		43		5		52		188		240
- of which recognized in “Payroll and related cost”				29		3		32		188		220
- of which recognized in “Financial income (expense)”		4		14		2		20				20

Costs of defined benefit plans recognized in other comprehensive income consisted of the following:

2019 2018
(€ 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 financial assumptions 7 50 3 60 (31) 1
(30)

Experience (gains) losses (2) (9) 21 10 1 6 12 19
Return on plan assets (23)
(23)
21 21
Change in asset ceiling (5)
(5)
5 5
5 13 24 42 1 1 13 15

~~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, 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
December 31, 2018
Plan assets with a quoted market price 115 37 238 6 2 56 18 70 542
Plan assets without a quoted market price 3 3
115 37 238 6 2 56 21 70 545

	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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TABLE OF CONTENTS

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 ~~2020~~2021 consisted of the following:

		Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Other benefit plans			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	(%)		0.7		0.0-13.7		0.7		0.0-0.7
Rate of compensation increase	(%)		1.7		1.3-12.5					(%)		1.7		1.3-12.5
Rate of price inflation	(%)		0.7		0.8-11.3		0.7		0.7	(%)		0.7		0.8-11.3		0.7		0.7
Life expectations on retirement at age 65	(years)				13-25		24			(years)				13-25		24
2018
Discount rate	(%)		1.5		0.8-18.0		1.5		0.2-1.5
Rate of compensation increase	(%)		2.5		1.5-16.5
Rate of price inflation	(%)		1.5		0.8-16.0		1.5		1.5
Life expectations on retirement at age 65	(years)				13-25		24.0

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
~~2018~~
~~Discount rate~~	~~(%)~~		~~1.5-1.9~~		~~0.8-2.9~~		~~3.7-18.0~~		~~8.0-13.3~~		~~0.8-18.0~~
~~Rate of compensation increase~~	~~(%)~~		~~1.5-3.0~~		~~2.5-3.8~~		~~5.0-16.5~~		~~10.0-13.3~~		~~1.5-16.5~~
~~Rate of price inflation~~	~~(%)~~		~~1.5-2.0~~		~~0.8-3.3~~		~~3.7-16.0~~		~~3.5-5.0~~		~~0.8-16.0~~
~~Life expectations on retirement at age 65~~	~~(years)~~		~~21-22~~		~~23-25~~		~~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		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		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								(12)		13		8
Foreign defined benefit plans		(67)		77		31		18				34		(67)		77		31		18				34
FISDE, foreign medical plans and other		(9)		10						10				(9)		10						10
Other benefit plans		(4)		1		1								(4)		1		1
December 31, 2018
Italian defined benefit plans		(12)		13		8
Foreign defined benefit plans		(58)		65		23		15				18
FISDE, foreign medical plans and other		(7)		8						6
Other benefit plans		(5)		3		1

The sensitivity analysis was performed based on the results for each plan through assessments calculated considering modified parameters.

~~F-69~~

~~TABLE OF CONTENTS~~

The amount of contributions expected to be paid for employee benefit plans in the next year amounted to ~~€130~~€132 million, of which ~~€57~~€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, 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
December 31, 2018
2019 15 54 9 81
2020 16 56 7 72
2021 18 63 6 67
2022 14 64 6 20
2023 11 74 6 17
2024 and thereafter 201 74 114 57
Weighted average duration (years) 10.1 17.4 12.8 2.6

~~22 Deferred tax assets and liabilities~~

(€ million) December 31, 2019 December 31, 2018
Deferred tax liabilities before offsetting 9,583 7,956
Deferred tax assets available for offset (4,663) (3,684)
Deferred tax liabilities 4,920 4,272
Deferred tax assets before offsetting (net of accumulated write-down provisions) 9,023 7,615
Deferred tax liabilities available for offset (4,663) (3,684)
Deferred tax assets 4,360 3,931

(€ 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

~~F-70~~F-67

TABLE OF CONTENTS

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, 2019		Carrying amount at December 31, 2018		Carrying amount at December 31, 2020		Carrying amount at December 31, 2019
Deferred tax liabilities
Accelerated tax depreciation		6,796		6,612		6,171		6,796
Leasing		1,375				1,089		1,375
Difference between the fair value and the carrying amount of assets acquired		617		849		415		617
Site restoration and abandonment (tangible assets)		126		85		199		126
Application of the weighted average cost method in evaluation of inventories		97		44		56		97
Other		572		366		651		572
		9,583		7,956		8,581		9,583
Deferred tax assets, gross
Carry-forward tax losses		(6,065)		(5,528)		(6,983)		(6,065)
Site restoration and abandonment (provisions for contingencies)		(2,242)		(1,986)		(2,211)		(2,242)
Timing differences on depreciation and amortization		(2,022)		(2,104)		(2,206)		(2,022)
Accruals for impairment losses and provisions for contingencies		(1,513)		(1,460)		(1,371)		(1,513)
Impairment losses						(1,213)		(946)
Leasing		(1,385)				(1,113)		(1,385)
Impairment losses		(946)		(792)
Employee benefits						(213)		(209)
Over/Under lifting		(525)		(604)		(211)		(525)
Employee benefits		(209)		(212)
Unrealized intercompany profits		(120)		(124)		(117)		(120)
Other		(740)		(546)		(593)		(740)
		(15,767)		(13,356)		(16,231)		(15,767)
Accumulated write-downs of deferred tax assets		6,744		5,741		9,065		6,744
Deferred tax assets, net		(9,023)		(7,615)		(7,166)		(9,023)

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TABLE OF CONTENTS

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, 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)
Carrying amount at December 31, 2017 10,169 (13,609) 5,262 (8,347)
Changes in accounting policies (IFRS 15) 37 (237) (237)
Carrying amount at January 1, 2018 10,206 (13,846) 5,262 (8,584)
Additions 1,147 (1,478) 253 (1,225)
Deductions (802) 1,523 (43) 1,480
Currency translation differences 283 (278) 71 (207)
Change in the scope of consolidation (2,778) 813 813
Other changes (100) (90) 198 108
Carrying amount at December 31, 2018 7,956 (13,356) 5,741 (7,615)

~~The first application of IFRS 16 is disclosed in note 3 — Changes in accounting policies.~~

(€ 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 ~~€21,360~~€23,325 million, ~~out~~ of which ~~€15,256~~€17,323 million can be carried forward indefinitely. Carry-forward tax losses were ~~€12,039~~€13,153 million and ~~€9,321~~€10,172 million at Italian

~~F-71~~

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subsidiaries and foreign subsidiaries, respectively. Deferred tax assets recognized on these losses amounted to ~~€2,936~~€3,734 million and ~~€3,129~~€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, which will be utilized in future years to offset expected taxable profit.~~losses. The corresponding average rate for foreign subsidiaries was ~~33.6%~~31.9%.

Accumulated write-downs of deferred tax assets related to Italian companies for ~~€5,329~~€7,090 million and non-Italian companies for ~~€1,415~~€1,975 million.

Taxes are also described in note 32 — Income taxes.

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23 Derivative financial instruments and hedge accounting

	December 31, 2019						December 31, 2018						December 31, 2020						December 31, 2019
(€ million)	Fair value asset		Fair value liability		Level of Fair value		Fair value asset		Fair value liability		Level of Fair value		Fair value asset		Fair value liability		Level of Fair value		Fair value asset			Fair value liability		Level of Fair value
Non-hedging derivatives
Derivatives on exchange rate
- Currency swap		97		43		2		99		46		2		125		127		2		97			43		2
- Interest currency swap		26				2		14		71		2		128		2		2		26					2
- Outright		8		5		2		3		5		2		4		7		2		8			5		2
		131		48				116		122				257		136				131			48
Derivatives on interest rate
- Interest rate swap		13		34		2		18		6		2		23		74		2		13			34		2
		13		34				18		6				23		74				13			34
Derivatives on commodities
- Future		192		181		1		1,060		1,107		1		418		447		1		192			181		1
- Over the counter		89		58		2		306		284		2		89		77		2		89			58		2
- Other		12				2		1		5		2		5				2		12					2
		293		239				1,367		1,396				512		524				293			239
		437		321				1,501		1,524				792		734				437			321
Trading derivatives
Derivatives on commodities
- Over the counter		2,387		1,953		2		992		1,031		2		1,167		1,451		2		2,387			1,953		2
- Future		348		313		1		367		263		1		440		525		1		348			313		1
- Options		21		22		2		80		71		2		4		3		2		21			22		2
		2,756		2,288				1,439		1,365				1,611		1,979				2,756			2,288
Cash flow hedge derivatives
Derivatives on commodities
- Over the counter		1		596		2		311		196		2		209		30		2		1			596		2
- Future		34		148		1								119		8		1		34			148		1
- Options				2		2		26		15		1				51		2					2		2
		35		746				337		211				328		89				35			746
Option embedded in convertible bonds		11		11		2		21		21		2		2		2		2		11			11		2
Gross amount		3,239		3,366				3,298		3,121				2,733		2,804				3,239	��		3,366
Offsetting		(612)		(612)				(1,636)		(1,636)				(1,033)		(1,033)				(612)			(612)
Net amount		2,627		2,754				1,662		1,485				1,700		1,771				2,627			2,754
Of which:
- current		2,573		2,704				1,594		1,445				1,548		1,609				2,573			2,704
- non-current		54		50				68		40				152		162				54			50

~~Derivative~~

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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 ~~the basis of~~ market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace.

Fair values of non-hedging derivatives ~~consisted of~~related to derivatives that did not meet the formal criteria to be designated as hedges under IFRS.

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Fair values of trading derivatives ~~consisted~~comprised forward sale contracts of natural gas for physical delivery which were not entitled to the own use exemption, as well as derivatives ~~entered~~ for proprietary trading ~~purposes and proprietary trading.~~activities.

Fair value of cash flow hedge derivatives related to commodity hedges were entered ~~into~~ by the Global Gas & ~~Power~~LNG Portfolio segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future ~~sale~~trade transactions of gas or electricity or on already contracted ~~sales~~trades due to different indexation mechanisms of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 25 — Shareholders’ equity and in note 29 — Costs. Information on hedged risks and hedging policies is disclosed in note 27 — Guarantees, commitments and risks — Risk factors.

~~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 the Gas & Power segment.~~

~~During 2019, there were no transfers between the different hierarchy levels of fair value.~~

~~Hedging derivative instruments are disclosed below:~~

December 31, 2019 December 31, 2018
(€ 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 2,179 (1,357) (2) 3,528 404 2
- Future 1,245 (61) 71 (6) (2)
3,424
(1,418)

(2)
3,599 398

In 2019, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €1,902 million was hedged by using, in a fair value hedge relationship, negative exchange differences for €21 million resulting on a portion of bonds denominated in U.S. dollars amounting to €1,844 million.

~~The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge is provided below:~~

December 31, 2019 December 31, 2018
(€ 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 1,444 (656) (739) (389) (13) 642
1,444 (656) (739) (389) (13) 642

Eni’s results of operations are affected by fluctuations in the price of commodities. To that end, Eni enters into commodities derivatives traded on organized markets (like MTF and OTF) and commodities derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with underlying commodities being crude oil, gas, refined products, electricity or emission certificates that are not settled through physical delivery of the underlying commodity but are designated as hedging instruments in a cash flow hedge relation.

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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)	2019		2018		2017		2020		2019		2018
Net income (loss) on cash flow hedging derivatives		(2)				12		(1)		(2)
Net income (loss) on other derivatives		289		129		(44)		(765)		289		129
		287		129		(32)		(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 in the Gas & Power segment.~~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)

~~Finance income (loss) on derivative financial instruments consisted of the following:~~

(€ million)	2019		2018		2017		2020		2019		2018
Derivatives on exchange rate		9		(329)		809		391		9		(329)
Derivatives on interest rate		(23)		22		28		(40)		(23)		22
		(14)		(307)		837		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 in the Gas & Power segment.~~commodities.

~~Finance income (expense) with related parties~~More information is disclosed in note 36 — Transactions with related parties.

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24 Assets held for sale and liabilities directly associated with assets held for sale

As of December 31, ~~2019,~~2020, assets held for sale related to sales of tangible assets for ~~€18 million.~~€44 million (€18 million at December 31, 2019).

~~In the course of 2019, Eni finalized the sale of Agip Oil Ecuador BV, which retains a service contract for the development of Villano oil field, and of a minority investment.~~

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25 ~~Shareholders’~~Equity

Equity attributable to equity holders of Eni

~~Eni shareholders’ equity~~

(€ million) December 31,
2019 December 31,
2018
Share capital 4,005 4,005
Retained earnings 37,436 36,702
Cumulative currency translation differences 7,209 6,605
Legal reserve 959 959
Reserve for treasury shares 981 581
Reserve related to the fair value of cash flow hedging derivatives net
of the tax effect (465) (9)
Reserve related to the defined benefit plans net of tax effect (173) (130)
Other comprehensive income on equity-accounted investments 60 66
Other comprehensive income on other investments 12 15
Other reserves 190 190
Treasury shares (981) (581)
Interim dividend (1,542) (1,513)
Net profit (loss) for the year 148 4,126
47,839 51,016

(€ 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, ~~2019,~~2020, the parent company’s issued share capital consisted of €4,005,358,876 (same amount as of December 31, 2019) represented by ~~3,634,185,330~~3,605,594,848 ordinary shares without nominal value ~~(same amounts as of~~(3,634,185,330 at December 31, ~~2018)~~2019).

On May ~~14, 2019,~~13, 2020, Eni’s Shareholders’ Meeting ~~resolved:~~declared: (i) to distribute a dividend of ~~€0.41~~€0.43 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the ~~2018~~2019 dividend of ~~€0.83~~€0.86 per share, of which ~~€0.42~~€0.43 per share ~~was already~~ paid as interim ~~dividend in September 2018.~~dividend. The ~~final amount~~balance was paid on 22 May ~~2019,~~20, 2020, to shareholders on the register on May ~~20, 2019,~~18, 2020, record date on May ~~21, 2019;~~19, 2020; (ii) to ~~authorise~~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 ~~— pursuant to and for the purposes of~~on September 15, 2020, in accordance with Article ~~2357~~2433-bis, paragraph 5 of the Italian Civil ~~Code — to proceed, within a period of eighteen months~~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 ~~resolution,~~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 ~~purchase~~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 ~~maximum number~~subsequent increase of shares equal to 67,000,000 ordinary shares of the Company, representing about 1.84% of the share capital of Eni SpA, for a total outlay of up to €1,200 million. In execution of this resolution at December 31, 2019, 28,590,482 shares were acquired for a total consideration of €400 million.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 ~~period~~periods to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings.

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Reserves for Other Comprehensive Income ~~reserves~~

Cash flow hedge derivatives Defined benefit plans* Other
comprehensive
income on
equity-accounted
investments Investments
valued at
fair value
(€ million) Gross
reserve Deferred
tax
liabilities Net
reserve Gross
reserve Deferred
tax
liabilities Net
reserve
Reserve as of December 31, 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
Reserve as of December 31, 2017 240 (57) 183 (133) 19 (114) 90
Changes of the year 399 (116) 283 (15) (2)
(17)
(24) 15
Foreign currency translation differences 1 (1)
Change in scope of consolidation 4 (3) 1
Reversal to inventories adjustments (10) 3
(7)

Reclassification adjustments (642) 174
(468)

Reserve as of December 31, 2018 (13) 4 (9) (143) 13 (130) 66 15

	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, ~~2019~~2020 includes €7 million relating to equity-accounted ~~investments.~~investments (€7 million at December 31, 2019)

Other reserves

Other reserves related ~~to: (i)~~to a reserve of €127 million representing the increase in equity attributable to Eni ~~shareholders’ equity~~ associated with a business combination under common control, whereby the parent company Eni SpA divested its ~~subsidiaries; (ii) a reserve of €63 million deriving from Eni SpA’s equity.~~subsidiaries.

~~Cumulative foreign currency translation differences~~

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~~The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.~~

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Treasury shares

A total of ~~61,635,679~~33,045,197 of Eni’s ordinary shares ~~(33,045,197~~(61,635,679 at December 31, ~~2018)~~2019) were held in treasury for a total cost of ~~€981~~€581 million (€~~581~~981 million at December 31, ~~2018)~~2019).

On ~~April~~May 13, ~~2017,~~2020, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan ~~2017-2019~~2020-2022 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 1120 million of treasury shares in service of the Plan.

~~Interim dividend~~

The interim dividend for the year 2019 amounted to €1,542 million corresponding to €0.43 per share, as resolved by the Board of Directors on 19 September 2019, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on 25 September 2019.

Distributable reserves

As of December 31, ~~2019,~~2020, equity attributable to Eni ~~shareholders’ equity~~ included distributable reserves of approximately ~~€43~~€30 billion.

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Reconciliation of net profit and ~~shareholders’~~ equity attributable to Eni of the parent company Eni SpA to consolidated net profit and ~~shareholders’~~ equity attributable to Eni

	Net profit				Shareholders’ equity				Net profit				Shareholders’ equity
(€ million)	2019		2018		December 31, 2019		December 31, 2018		2020		2019		December 31, 2020		December 31, 2019
As recorded in Eni SpA’s Financial Statements		2,978		3,173		41,636		42,615		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		(2,800)		(134)		5,211		7,183		(10,660)		(2,800)		(8,839)		5,211
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(6)				202		153		(6)		(6)		193		202
- adjustments to comply with Group accounting policies		(348)		862		1,424		2,000		264		(348)		2,086		1,424
- elimination of unrealized intercompany profits		(74)		177		(593)		(519)		88		(74)		(478)		(593)
- deferred taxation		405		59		20		(359)		79		405		(176)		20
		155		4,137		47,900		51,073		(8,628)		155		37,493		47,900
Non-controlling interest		(7)		(11)		(61)		(57)		(7)		(7)		(78)		(61)
As recorded in Consolidated Financial Statements		148		4,126		47,839		51,016		(8,635)		148		37,415		47,839

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26 Other information

Supplemental cash flow information

(€ million)	2019		2018		2017		2020		2019		2018
Investment in consolidated subsidiaries and businesses												��
Current assets		1		44				15		1		44
Non-current assets		12		198				193		12		198
Net borrowings				11				(64)				11
Current and non-current liabilities		(6)		(47)				(17)		(6)		(47)
Net effect of investments		7		206				127		7		206
Fair value of investments held before the acquisition of control				(50)								(50)
Non-controlling interests		(2)						(15)		(2)
Gain on a bargain purchase				(8)								(8)
Purchase price		5		148				112		5		148
less:
Cash and cash equivalents				(29)				(3)				(29)
Consolidated subsidiaries and businesses net of cash and cash equivalent acquired		5		119				109		5		119
Disposal of consolidated subsidiaries and businesses
Current assets		77		328		166				77		328
Non-current assets		188		5,079		814				188		5,079
Net borrowings		11		785		(252)				11		785
Current and non-current liabilities		(57)		(3,470)		(205)				(57)		(3,470)
Net effect of disposals		219		2,722		523				219		2,722
Reclassification of foreign currency translation differences among other items of comprehensive income		(24)		113						(24)		113
Fair value of share capital held after the sale of control				(3,498)								(3,498)
Fair value valuation for business combination				889								889
Gain (loss) on disposal		16		13		2,148				16		13
Selling price		211		239		2,671				211		239
less:
Cash and cash equivalents		(24)		(286)		(9)				(24)		(286)
Consolidated subsidiaries and businesses net of cash and cash equivalent disposed of		187		(47)		2,662				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.

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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~~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, 2019		December 31, 2018		December 31, 2020		December 31, 2019
Consolidated subsidiaries		4,323		5,082		4,758		4,323
Unconsolidated subsidiaries		197		196		176		197
Joint ventures and associates		4,075		4,056		3,800		4,075
Others		267		163		150		267
		8,862		9,497		8,884		8,862

Guarantees ~~include~~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 ~~third-party contractors~~the participated Saipem joint-venture to Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) for the proper and ~~lenders who have~~timely completion of a ~~certain contractual obligations to build and finance~~project for the construction of anthe Milan-Bologna fast track railway by the CEPAV (Consorzio Eni per l’Alta Velocità) Uno; (iv) a guarantee issued in favor of Gulf LNG ~~Floating Production unit~~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 ~~development~~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 ~~gas reserves discovered in Area 4 offshore Mozambique. The total value of~~project FLNG vessel. At December 31, 2020, the contract is €4,673 million. Eni is operator of the project with a 25% indirect interest through a 35.71% stake in the joint operation Mozambique Rovuma Venture SpA. The final investment decision (FID) for the Coral project was made on June 1, 2017. The FLNG plant is designed to treat approximately 3.37 million tonnes per year of LNG. A special purpose entity was established, Coral FLNG SA (Eni’s interest 25%). This entity will operate the vessel in accordance with a service agreement (EPCC) for the liquefaction, storage and loading of the LNGunderlying commitment issued on behalf of the Concessionaires of Area 4 and of the other two partners of Mozambique Rovuma Venture SpA, CNPC and ExxonMobil in proportion to their participating interest in the Exploration and Production Concession Contract (EPCC) of Area 4, equal to 20% and 25%, respectively. The LNG will be supplied to BP under a long-term LNG sale andthird parties covered by such guarantees was €87 million (€80 million at December 31, 2019).

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purchase agreement with a take-or-pay clause and a twenty-year term, providing an option of extending the duration for up to ten consecutive years. Eni issued a parent company guarantee, whereby it irrevocably and unconditionally guarantees the Technip — JGC — Samsung Heavy Industries (TJS) consortium (the beneficiaries) for the due and proper performance of the obligations of Coral FLNG SA in connection with execution of the Engineering Procurement Construction Installation and Commissioning (EPCIC) contract, up to the maximum liability of €1,168 million equal to 25% of the value of the contract. The maximum liability will be automatically reduced by any amount paid to the beneficiaries in respect of the guaranteed obligations. The financing of the project is carried out partly through fundsAs provided by the venturers and partly by a project financing with Export Credit Agencies and commercial banks for a total amount of €4,164 million. During the construction and the commissioning of the FLNG plant, the project financing agreement will be supported by a debt service undertaking (DSU), up to a maximum liability of €1,425 million in proportion to Eni’s participating interest equal to 25% in the industrial initiative. Subsequently, in the running phase of the plant, once the performance tests of the vessel have been validated by the lenders, that guarantee will be released and the financing facility will convert to non-recourse, terminating the obligations of the venturers of Area 4 towards the lenders. Once vessel operations start, the lenders will be guaranteed only by the cash flows of the sale of LNG volumes treated by the vessel and delivered to the buyer, excluding the gas reserves from the scope of the guarantee. The financing and any collateral costs will be reimbursed to the lenders through a “pay-when-paid” clause, whereby loan repayments will be made through the cash flows associated with the sale of the LNG arising from the project to the long-term buyer, without any obligations from Eni and Concessionaires to guarantee the performance of Coral FLNG SA towards the lenders. Furthermore, the Concessionaries opened a credit facility which committed each Concessionary to finance pro-quota: (i) the share of capital expenditures to be borne by the Mozambique State-owned company ENH up to a maximum liability of €123 million in Eni’s share; (ii) the share of the debt service undertaking by ENH up to a maximum liability of €158 million in Eni’s share. As a final point, as provided by the EPCCcontract 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 ~~initial~~ development plan of the ~~Area~~ 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 ~~€1,335~~€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 ~~the EPCIC of~~ Area 4.

Guarantees issued on behalf of consolidated subsidiaries of €4,323 million (€5,082 million at December 31, 2018) primarily consisted of guarantees given to third parties relating to bid bonds and performance bonds for €2,886 million (€2,576 million at December 31, 2018). In 2019 a bank guarantee of €1,010 million, issued on behalf of GasTerra to obtain the waiver to a temporary seizure of Eni’s investment in Eni International BV, which was ordered by a Netherlands Court in July 2016, was settled. In July 2019, the arbitration proceeding, initiated by the parties to settle the dispute, issued an award favourable to Eni and ruled the claim of GasTerra for a price adjustment to the gas supplies to be without merit, which in the first partial award was the basis whereby GasTerra obtained the seizure order. On July��24, 2019 upon Eni’s request and GasTerra’s consent, the bank guarantee was terminated. GasTerra has reserved its rights of appeal. At December 31, 2019, the underlying commitment issued on behalf of consolidated subsidiaries covered by such guarantees was €4,013 million (€5,000 million at December 31, 2018).

Guarantees issued on behalf of joint ventures and associates of €4,075 million (€4,056 million at December 31, 2018) primarily consisted of: (i) unsecured guarantees and other guarantees for €1,676 million issued towards banks and other lending institutions in relation to loans and lines of credit received (€1,664 million at December 31, 2018), of which €1,425 million (€1,397 million at December 31, 2018) related to guarantees issued as part of the Coral development project in Area 4 offshore Mozambique on behalf of Coral South FLNG DMCC with respect to the financing agreements of the project with Export Credit Agencies and banks; and (ii) guarantees given to third parties relating to bid

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bonds and performance bonds for €1,661 million (€1,644 million at December 31, 2018), of which €1,168 million (€1,147 million at December 31, 2018) related to guarantees issued towards the contractors who are building the FLNG vessel as part of the Coral development project offshore Mozambique; (iii) an unsecured guarantee of €499 million (€499 million at December 31, 2018) 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 €181 million (€177 million at December 31, 2018). At December 31, 2019, the underlying commitment issued on behalf of joint ventures and associates covered by such guarantees was €2,109 million (€2,159 million at December 31, 2018).

Commitments and risks

(€ million)	December 31, 2019		December 31, 2018		December 31, 2020		December 31, 2019
Commitments		74,338		54,611		69,998		74,338
Risks		676		673		600		676
		75,014		55,284		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 basis of~~ the capital expenditures to be incurred, to be ~~€65,374~~€64,294 million (€~~52,397~~65,374 million at December 31, ~~2018)~~2019). The ~~increase~~decrease of ~~€12,977~~€1,080 million was incurred in connection with: (a) the issuance of new parent company guarantees of €9,794 million of which €8,904 million issued on behalf of Eni Abu Dhabi BV in relation to the entry into the exploration permits of Blocks 1 and 2 and €890 million on behalf of Eni RAK BV in relation to the entry and the start of exploration activities in Block A in the United Arab Emirates. These parent company guarantees are in addition to those issued in 2018 as part of the transactions with the Abu Dhabi State oil company ADNOC, whereby Eni acquired participating interests in the two offshore concessions in production of Lower Zakum (Eni’s interest 5%) and Umm Shaif and Nasr (Eni’s interest 10%) forprimarily determined by negative exchange rate differences; (ii) a period of 40 years and a maximum amount of €13,356 million and in the concession under development of Gasha (Eni’s interest 25%) for a period of 40 years and a maximum amount of €22,261 million. These guarantees were issued to cover the contractual obligations towards the State company, deriving from oil operations related to the Concession Agreements including, in particular, the achievement of some production targets and recovery factors of reserves in the medium and long term, an asset integrity plan and optimization and maintenance of the production after reaching the plateau, the transfer of technologies and the adoption of best-in-class operating standards in HSE. The guarantees do not cover any loss of profit or production deriving from failure to achieve the targets; (b) a new parent company guarantee of ~~€445~~€3,260 million ~~issued in relation to an asset swap with Lukoil involving Blocks 10 and 12 in the offshore of Mexico. This parent company guarantee is in addition to those issued in previous years for €9,194~~(€6,527 million of which €6,968 million issued in 2018 following the awarding of new exploration licenses in the offshore of Mexico and the final investment decision for the development of the offshore reserves in Area 1; (c) a new parent company guarantee for €1,781 million in relation to the acquisition of the upstream assets of ExxonMobil by the joint venture Vår Energi AS intended to cover the decommissioning contractual obligations; (ii) two parent company guarantees for a total amount of €6,527 millionat December 31, 2019) given on behalf of Eni Abu Dhabi Refining & Trading BV following the Share Purchase Agreement to acquire from ~~ADNOC~~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 ~~first~~decrease of €3,267 million related to the extinction of the parent company guarantee, ~~of €2,965 million was~~ issued to guarantee the obligations under the Share Purchase Agreement, ~~and will remain in place until~~following the payment of the ~~Deferred Consideration expected by March 31, 2020.~~deferred consideration amounting to €73 million. The ~~second~~ parent company guarantee ~~of €3,562 million~~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 ~~regasified~~re-gasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031). The expected commitments were estimated at ~~€1,978~~€1,672 million (€~~2,079~~1,978 million at December 31, ~~2018)~~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.

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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 ~~counterparties~~counterparty an equitable compensation of €324 ~~million to Eni’s counterparties.~~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. At~~action; (iv) the ~~moment,~~commitment to purchase of a 20% stake of the ~~risk~~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 ~~losing~~Finproject SpA, a company engaged in the ~~proceeding is considered unlikely; (iv)~~compounding sector for €150 million; (vi) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest ~~€114~~€108 million (€~~116~~114 million at December 31, ~~2018)~~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”; (v) the commitment of €105 million for the acquisition of a 70% stake of Evolvere SpA, a company leader in the distributed generation of energy from renewable sources; the acquisition was finalized in January 2020..

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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 ~~€248~~€230 million (€~~244~~248 million at December 31, ~~2018)~~2019); (ii) assets of third parties under the custody of Eni for ~~€428~~€370 million (€~~429~~428 million at December 31, ~~2018)~~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 ~~€13~~€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 ~~also~~ include the agreements entered into for forestry initiatives, implemented within the low carbon strategy defined by the Company, ~~and in particular~~ concerning the commitments for the purchase, ~~up to~~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 ~~assurances~~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 ~~liquidity.~~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

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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.

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Market risk — Exchange rate

Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than euro (mainly U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rate fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than euro are translated from their functional currency into euro. Generally, an appreciation of U.S. dollar versus euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s 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 ~~finance~~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. A decrease in oil&gas prices generally, has a negative impact on Eni’s results of operations and vice versa, and may jeopardize the achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of ~~risk.~~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

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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 ~~2019,~~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 ~~2018.~~2019. The following tables show amounts in terms of VaR, recorded in ~~2019~~2020 (compared with ~~2018)~~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)~~(DVBP).

(Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%)


	2019								2018								2020								2019
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end
Interest rate(a)		5.19		2.44		3.80		3.00		3.65		1.80		2.73		2.99		7.39		1.18		2.93		1.34		5.19		2.44		3.80		3.00
Exchange rate(a)		0.41		0.07		0.17		0.15		0.57		0.09		0.28		0.25		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%)


	2019								2018								2020								2019
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end
Commercial exposures – Management Portfolio (a)		23.03		7.74		11.22		9.11		18.60		6.79		11.04		7.50		16.10		3.02		8.50		3.02		23.03		7.74		11.22		9.11
Trading(b)		1.60		0.25		0.51		0.31		2.28		0.26		0.73		0.27		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 & ~~Power Division)~~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 & ~~Power~~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 ~~GLP~~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)


	2019								2018								2020								2019
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end
Strategic liquidity(a)		0.37		0.31		0.35		0.33		0.35		0.25		0.29		0.25		0.37		0.29		0.32		0.30		0.37		0.31		0.35		0.33

(a)

Management of strategic liquidity portfolio ~~in € currency~~ starting from July 2013.

(Sensitivity — Dollar value of 1 basis point — DVBP)


	2019								2018								2020								2019
($ million)	High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end		High		Low		Average		At year end
Strategic liquidity~~(b)~~(a)		0.05		0.02		0.04		0.05		0.04		0.01		0.02		0.02		0.07		0.03		0.05		0.05		0.05		0.02		0.04		0.05

~~(b)~~(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 ~~with regard to~~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 ~~the structured~~sales contracts on commodities related to Eni’s ~~core business,~~businesses, and by financial nature, in relation to the financial instruments ~~substantially~~ 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 ~~the basis of~~ formal procedures for the assessment ~~and assignment~~ of commercial counterparties, the monitoring of credit exposures, credit recovery activities and disputes. ~~At a corporate level, the general guidelines~~The credit worthiness of businesses and ~~methods for quantifying and controlling customer risk, in particular for commercial counterparties, are~~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 as defined by the Company’s Board of Directors ~~taking into account the credit~~and based on ratings provided for by primary credit rating ~~agencies on the marketplace.~~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 ~~on a~~ daily ~~basis~~ 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 ~~instruments, favouring~~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 ~~as a consequence of the availability of~~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 ~~€14.9~~€16.3 billion were drawn as of December 31, ~~2019.~~2020 (€13.9 billion by Eni SpA).

The Group has credit ratings of A- outlook ~~stable~~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 ~~2019,~~2020, the rating of Eni remained unchanged.

~~In 2019, Eni issued bonds for €1,635 million, of which €746 million as~~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 ~~€889 million through~~classified as equity items. The rating agencies assigned to the bonds the following ratings Baa3 / BBB / BBB (Moody’s / S&P / Fitch) and an ~~issue amounting to $1 billion in the U.S. and international markets.~~“equity credit” of 50%.

As of December 31, ~~2019,~~2020, Eni maintained short-term uncommitted unused borrowing facilities of ~~€13,299~~€7,183 million. ~~Long-term committed~~Committed unused borrowing facilities amounted to ~~€4,667~~€5,295 million, of which ~~€450~~€4,750 million due ~~within~~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 ~~finance debts~~liabilities, trade and ~~lease liabilities~~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) 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

Maturity year
(€ million) 2019 2020 2021 2022 2023 2024 and
thereafter Total
December 31, 2018
Non-current financial liabilities (including the
current portion) 3,301 2,958 1,541 1,253 2,714 11,723 23,490
Current financial liabilities 2,182 2,182
Fair value of derivative instruments 1,445 13 1 21 5 1,485
6,928 2,971 1,542 1,274 2,714 11,728 27,157
Interest on finance debt 655 545 436 330 320 1,677 3,963
Financial guarantees 668 668

	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 ~~€2,953~~€2,429 million ~~refer~~(€2,953 million at December 31, 2019) pertained to the share ~~pertaining to the partners~~ of joint operators participating in unincorporated ~~joint operations~~ventures operated by Eni which will be recovered through ~~recharges~~a partner-billing process.

The table below presents the timing of ~~cash calls.~~

~~Expected payments~~the expenditures for trade and other ~~payables~~payables.

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

Maturity year
(€ million) 2019 2020 – 2023 2024 and
thereafter Total
December 31, 2018
Trade payables 11,645 11,645
Other payables and advances 5,102 59 96 5,257
16,747 59 96 16,902

	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 obligations3628

In addition to lease, financial, trade and other liabilities represented in the balance sheet, the ~~company~~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														Maturity year
(€ million)	2020		2021		2022		2023		2024		2025 and thereafter		Total		2021		2022		2023		2024		2025		2026 and thereafter		Total
Decommissioning liabilities(a)		331		325		163		179		424		12,052		13,474		400		237		202		425		276		10,433		11,973
Environmental liabilities		403		368		319		238		198		1,065		2,591		383		323		267		255		196		839		2,263
Purchase obligations(b)		9,938		9,912		9,467		9,530		9,722		77,914		126,483		8,041		7,644		7,342		8,150		8,613		63,864		103,654
- Gas
- take-or-pay contracts		7,117		9,140		8,912		9,100		9,410		77,239		120,918		6,196		6,852		6,809		7,691		8,392		63,477		99,417
- ship-or-pay contracts		1,070		532		454		412		296		646		3,410		893		519		480		439		212		359		2,902
- Other purchase obligations		1,751		240		101		18		16		29		2,155		952		273		53		20		9		28		1,335
Other obligations		7		1								106		114		2										106		108
- Memorandum of intent – Val d’Agri		7		1								106		114		2										106		108
Total		10,679		10,606		9,949		9,947		10,344		91,137		142,662		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.

28

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 ~~€31.5~~€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) 2020 2021 2022 2023 2024 and
thereafter Total
Committed projects 5,570 4,054 2,611 1,544 2,669 16,448

36

~~Contractual obligations related to employee benefits are indicated in note 21 — Provisions for employee benefits.~~

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	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

~~The carrying amount of financial instruments and the relevant economic and equity effect consisted of the following:~~


	2019						2018							2020								2019
(€ million)	Carrying amount		Finance income (expense) recognized in				Carrying amount			Finance income (expense) recognized in				Carrying amount			Finance income (expense) recognized in					Carrying amount			Finance income (expense) recognized in
(€ million)	Carrying amount		Profit and loss account		Other comprehensive income		Carrying amount		Profit and loss account			Other comprehensive income		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 acount
Financial instruments at fair value with effects recognized in profit and loss account
Financial assets held for trading(a)		6,760		127				6,552			32				5,502			31			��		6,760			127
Non-hedging and trading derivatives(b)		(125)		273				177			(178)				(19)			(415)					(125)			273
Other investments valued at fair value(c)		929		247		(3)		919			231		15		957			150		24			929			247		(3)
Receivables and payables and other assets/liabilities valued at amortized cost
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other(d)		12,926		(409)				14,145			(343)				10,955			(213)					12,926			(409)
Financing receivables(e)		1,503		110				1,489			(139)				1,207			99					1,503			110
Securities(a)		55						64							55								55
Trade payables and other(a)		15,699		33				16,902			(28)				13,141			(31)					15,699			33
Financing payables(f)		24,518		(802)				25,865			(615)				26,686			(632)					24,518			(802)
Net assets (liabilities) for hedging derivatives (g)		(2)		(739)		(679)					642		(243)		(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 ~~income~~expense within “Other operating income (loss)” for ~~€287~~€766 million (income for ~~€129~~€287 million in ~~2018)~~2019) and as ~~loss~~income within “Finance income (expense)” for ~~€14~~€351 million (loss for ~~€307~~€14 million in ~~2018)~~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 ~~€432~~€226 million (net impairment losses for ~~€415~~€432 million in ~~2018)~~2019) and as income within “Finance income (expense)” for ~~€23~~€13 million (income for ~~€69~~€23 million in ~~2018)~~2019), including interest income calculated on the basis of the effective interest rate of ~~€26~~€22 million (interest income for ~~€38~~€26 million in ~~2018)~~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 ~~€99~~€92 million (income for ~~€129~~€99 million in ~~2018)~~2019) and net impairment losses for €1 million (net revaluations for €4 million ~~(net impairment losses for €275 million~~ in ~~2018)~~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 ~~€647~~€531 million (interest expense for ~~€605~~€647 million in ~~2018)~~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, 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
December 31, 2018
Financial assets
Trade and other receivables 15,634 1,533 14,101
Other current assets 4,455 1,636 2,819
Financial liabilities
Trade and other liabilities 18,280 1,533 16,747
Other current liabilities 7,048 1,636 5,412

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(€ 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 ~~€713~~€753 million (€~~1,347~~713 million at December 31, ~~2018)~~2019) and trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for ~~€187~~€2 million (€~~186~~187 million at December 31, ~~2018)~~2019); and (ii) other assets and liabilities for current financial derivatives of ~~€612~~€1,033 million (€~~1,636~~612 million at December 31, ~~2018)~~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. ~~Unless~~Generally and unless otherwise indicated, ~~no provisions have been made for~~ these legal proceedings ashave not been provisioned because Eni believes ~~that~~a negative ~~outcomes are not probable~~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 ~~(former Syndial 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 ~~presented a new clean-up program already deemed approvable by~~therefore decided to appeal against the ~~Ministry for~~sentence, in order to obtain an acquittal on the ~~Environment. Clean-up remediation activities have started. The Company has requested~~merits also in relation to the ~~dismissal~~positions of the ~~second proceeding.~~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 ~~proceeding~~preliminary hearing is ~~underway.~~still ongoing.

~~(iii)~~(iv) Eni Rewind SpA ~~(former Syndial 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 ~~underway.~~

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~~(iv)~~(v) Eni Rewind SpA ~~(former Syndial 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.

~~(v)~~(vi) Eni Rewind SpA ~~(former Syndial SpA)~~ — The Phosphate deposit at Porto Torres ~~site (1).~~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~~(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.

~~(vi)~~ 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 ~~(former Syndial SpA) — Phosphate deposit at Porto Torres site (2).~~ ~~In 2015,~~in relation to the ~~Public Prosecutor at~~liability pursuant to Legislative Decree 231/01. The Judge also ordered the indictment of the defendants before the Court of Sassari, ~~seized — as a probative measure —~~at the ~~containment systems for~~hearing on May 28, 2021, limited to the ~~meteoric waters in the area “Palte Fosfatiche” (phosphates deposit), located on the territory~~alleged crime of Porto Torres site. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up and management of radioactive waste. This investigation has been combined into the abovementioned one.environmental disaster.

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(vii) Eni Rewind SpA ~~(former Syndial 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~~Prosecutor and the plaintiffs appealed the ~~decision. The~~decision; a second instance ~~Judge~~judge ordered a complex ~~report, and stated~~appraisal, believing that they could not decide on the ~~appeal at that stage~~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, ~~appointed three experts. The proceeding is ongoing before~~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 ~~Court.~~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~~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

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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~~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. The Prosecutor requested Eni and all the defendants be put on trial,~~Company, pursuant to Legislative Decree No. 231/~~01.~~01, which presumes that companies are liable for crimes committed by their employees when performing job tasks. The trial started in November ~~2017~~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 ~~is ongoing.~~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 ~~— currently averted —~~ 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 ~~Company completed the arrangement~~characterization plan ~~for the internal and external areas~~ of the areas inside and outside the COVA ~~whose final report~~ was ~~examined~~approved by the relevant ~~authorities.~~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 ~~pollution~~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 ~~as communicated in December 2018 following the notification of the extension of the terms for preliminary investigations~~ 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. ~~Investigations are ongoing.~~ The Company has paid damages of an immaterial amount almost to ~~certain~~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.~~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 ~~charge~~charges against the CEO of the Refinery of Gela SpA and of the company itself ~~has been~~were dismissed, while a request to put on trial the CEO of ~~Enimed~~EniMed SpA and the company ~~were requested to be put on trial.~~was approved. The proceeding is ~~ongoing.~~

~~(xiii) Eni Rewind SpA (former Syndial SpA) — Environmental disaster at Ferrandina.~~ ~~In January 2018,~~in progress before the ~~Public Prosecutor~~Court of ~~Matera commenced a criminal~~Agrigento, to which the 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~~

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~~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~~has been transferred 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.territorial jurisdiction.

~~(xiv)~~(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.

(~~xv)~~(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 ~~ongoing.~~pending in the preliminary investigation phase.

~~(xvi)~~(xv) Raffineria di Gela SpA and Eni Rewind SpA ~~(former Syndial 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.

~~(xvii)~~(xvi) Eni Rewind SpA ~~(former Syndial SpA)~~ and Versalis — Mantua. Environmental crime ~~investigation~~investigation.~~. The~~ In August and September 2020, the Public Prosecutor of Mantua ~~has initiated a series of proceedings against companies~~notified the conclusion of the ~~Eni group and~~preliminary investigations relating to several criminal proceedings. Several employees of the Eni’s subsidiaries Versalis SpA and Eni ~~for alleged environmental crimes related to~~Rewind SpA as well as of a third-party company Edison SpA were notified of being under investigations. Furthermore the ~~Mantua industrial hub. Investigations, whose terms have been extended, are in progress. The Prosecutor of Mantua is proceeding~~above-mentioned entities were being held liable for the ~~crime of omitted clean-up, both according to the case foreseen~~alleged crimes committed on their own interest by ~~the Consolidated Environmental Text and for the hypothesis foreseen by the penal code “up to the present”. Eni companies are being investigated~~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 ~~(former Syndial SpA)~~ — Summon for alleged environmental damage caused by DDT pollution in ~~the~~ 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

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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~~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~~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. ~~In accordance with the law,~~Following this appeal, the Company appeared in Court. After the hearings in July 2020 and ~~its managers filed an appeal and a counter-appeal.~~in January 2021, the sentence is still ongoing.

(ii) Eni Rewind SpA ~~(former Syndial 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, ~~Syndial~~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.~~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. The Administrative Council of the Sicilian Region ruled on the appeals pending against various decisions of the Regional Administrative Court and essentially confirmed the cancellation of all administrative provisions subject to the dispute. The annulment of the provisions had, inter alia, retroactive effect to the time of their adoption and therefore excludes the risk of claims of any possible breach of administrative provisions. 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. AThe report, recalling the warning of 2017, confirmed the thesis of the ~~committee affirmed~~parties on the ~~2017 warning~~responsibility of the ~~Ministry~~companies co-located for the contamination of the Rada and ~~reaffirmed~~affirmed a breach of the ~~State agencies and local administrations’ view as~~aforementioned warning by the companies, also communicated to the ~~environmental liability to be charged to the companies operating in the area.~~Public Prosecutor's Office. In ~~coordination~~agreement with all the other companies ~~operating at the site, the~~involved, this report ~~is being appealed~~ and ~~further~~other parallel internal technical ~~analyses have been commenced~~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.~~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

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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~~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 ~~Syndial~~Eni Rewind to settle the case. The Company responded with a ~~counter-proposal~~counterproposal in July 2019. ~~The judge is verifying~~In September 2020, the ~~progress~~debate reopened and ~~status~~the drafting of an agreement shared between the parties and considered to be final also by the representatives of the ~~negotiations.~~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) ~~Eni Rewind SpA (former Syndial 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. An appeal by the Municipality before a Third Instance Court is pending.

~~(vi)~~ 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 tothat will be quantified ~~during~~in the ~~proceedings.~~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.

~~(vii)~~(vi) Eni ~~Spa~~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 ~~Eni Group companies~~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. ~~The proceedings are currently suspended and~~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 ~~jurisdictional competence.~~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

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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.

~~(ii) Algeria.~~ Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to Eni’s former subsidiary Saipem in Algeria. In 2011, Eni received from the Public Prosecutor of Milan an information request in accordance with the Italian Code of Criminal Procedure. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem SpA and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem SpA and Technip relating to the engineering of the ground section of a gas pipeline). The crime of international corruption is among the offenses pursuant to Legislative Decree No. 231/01, which provides for corporate liability for crimes committed by employees and prescribes punishments including fines and the disgorgement of profit. Eni also voluntarily provided to the Public Prosecutor documentation relating to the MLE project (in which Eni’s Exploration & Production Division participates), with respect to which investigations in Algeria are ongoing. In November 2012, the Public Prosecutor served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption pursuant to Legislative Decree No. 231/01. Furthermore, the Public Prosecutor requested the production of certain documents relating to certain activities in Algeria. Subsequently, the Public Prosecutor’s Office notified further measures and requests to Saipem, aimed at acquiring further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem SpA, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, the employment of whom was terminated at the beginning of 2013. In February 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced pursuant to Legislative Decree No. 231/01 with respect to Eni, Eni’s former CEO, Eni’s former CFO and another senior manager. Eni’s former CFO had previously served as Saipem’s CFO, including during the period in which alleged corruption took place and before being appointed as CFO of Eni on August 1, 2008. Following ~~receipt of~~ this notice, Eni conducted an internal investigation with the assistance of external consultants, in addition to the review activities performed by its audit and internal control departments and a team dedicated to the Algerian matters. The external consultants reached the following results: (i) the review of the documents seizedruling by the ~~Milan prosecutors and~~Court, the examination of internal records held by Eni’s global procurement department did not find any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on the MLE project, the only project that Eni understands tocriminal proceedings can be ~~under the prosecutors’~~considered concluded.

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~~investigation where the client is an~~(ii) Eni ~~Group company did not find evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling)~~Rewind SpA — Environmental disaster at Ferrandina. Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal, accounting and administrative issues. The findings of that review confirmed the autonomy of Saipem from the parent company during the relevant periods. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. In January 2015, the Public Prosecutor notified the conclusion of preliminary investigations relating to Eni, Saipem and eight persons (including, the former CEO and CFO of Eni SpA and the Chief Upstream Officer of Eni SpA who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor issued a notice of alleged international corruption against all such persons (including Eni SpA and Saipem SpA pursuant to Legislative Decree No. 231/01) in connection with the entry into intermediary contracts by Saipem in Algeria. In February 2015, the Public Prosecutor requested the indictment of all the investigated persons for international corruption as well as for tax offenses. In 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni SpA, former Chief Executive Officer and Chief Upstream Officer for all the alleged offenses. In February 2016, the Third Instance Court, upholding an appeal presented by the Public Prosecutor, reversed the dismissal and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of a new preliminary hearing in July 2016, the Judge ordered the trial for all defendants, including Eni SpA. At a hearing in February, 2018, the Public Prosecutor ~~concluding his indictment, requested — among other things — the imposition on Eni SpA~~ of Matera commenced a ~~pecuniary sanction. In September 2018, the Court of Milan rejected in part the charges~~criminal proceeding against a manager of the ~~Public Prosecutor~~Eni subsidiary Eni Rewind based on allegations of unlawful handling of waste and ~~issued~~environmental disaster as part of the reclaiming activities performed at an ~~acquittal verdict for Eni, for~~industrial site (Ferrandina/Pisticci in the ~~former CEO~~south of Italy). The charge related to an alleged spillover of effluent in the subsoil and ~~for~~then in a nearby river due to a damaged pipe dedicated to the ~~Company’s Chief Upstream Officer~~transportation of effluent to a disposal plant owned by a third party. At the preliminary hearing in ~~relation to all charges. The former CFO of Eni was also acquitted of charges relating to Eni’s involvement. In December 2018~~October 2019, the ~~court filed a written opinion setting forth~~Judge dismissed the case on the basis ~~for its rulings.~~that the defendant did not commit any crime. The ~~Public Prosecutor and the parties who were convicted in the first trial have appealed under the terms of the law.~~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~~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 ~~U.S.~~US Department of Justice (DoJ) and the ~~U.S.~~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 ~~U.S.~~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. ~~In September 2019, the~~The DoJ notified Eni that based on the information it currently possessed, ~~the DoJ was~~ closing its investigation of Eni in connection with Eni’s and Saipem’s businesses in Algeria without the filing of any ~~charges. Eni is currently in advanced discussions with~~charges, ordering the ~~SEC about a potential resolution~~closure of the ~~SEC’s investigation.~~

~~(iii) Block OPL 245 — Nigeria. A criminal case is pending before~~proceeding as communicated to the ~~Court of Milan alleging international corruption in connection with the acquisition in 2011~~market on October 1, 2019. In April 2020 Eni, having informed SEC of the ~~OPL 245 exploration block in Nigeria. In July 2014,~~acquittal pronounced on appeal on January 15, 2020, however concluded the ~~Public Prosecutor~~investigation by the US SEC on Algerian activities of ~~Milan served Eni~~Saipem SpA, with a ~~notice~~transaction that does not involve the admission of ~~investigation pursuant to Italian Legislative Decree No. 231/01.~~responsibility. The ~~proceeding was commenced following a claim filed by NGO ReCommon relating to alleged corruptive practices~~agreement provided for the payment of USD 19,750,000, which ~~according to the Public Prosecutor, allegedly involved the Resolution Agreement made on April 29, 2011 relating to the so-called Oil Prospecting License~~represents Eni’s part 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 U.S. Department of Justice and the U.S. 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 U.S. lawyers concluded that they detected no evidence of wrongdoingtax benefits obtained by ~~Eni~~Saipem in relation to the ~~2011 transaction with~~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 ~~Nigerian government~~municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Eni Rewind and Versalis for the ~~acquisition~~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 ~~OPL 245 license. In September 2014,~~hazardous waste materials back to the ~~Public Prosecutor notified Eni of a restraining order issued~~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 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 CEOthird 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 ~~former Chief Development, Operation & Technology Officer~~site. In June 2017, the Judge accepted all the defensive instances of Eni Rewind and Versalis, judging 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

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~~reaffirmed the seizure. In December 2016, the Public Prosecutor of Milan notified Eni~~requests of the ~~conclusion~~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 ~~preliminary investigation and requested Eni’s CEO,~~proceeding. In April 2018, the ~~Chief Development, Operations and Technological Officer and~~First Instance Judge rejected 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 investigationcounterclaim filed by the ~~Public Prosecutor,~~Municipality. In July 2020, the ~~independent US-based law firm~~appeal to the Third Instance Court was ~~requested to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the prior review.~~held. The U.S. law firm was also provided with the documentation filed in the Nigerian proceeding mentioned below. The independent U.S. law firm concluded that the reappraisal of the matter in light of the new documentation available did not alterJudge confirmed 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~~previous degrees 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 and is currently ongoing.

~~In a separate criminal proceeding, two defendants, neither of whom is a current or former employee of~~judgment, only ordering the Company ~~chose~~ to ~~have their liability determined by~~pay the Judge for the Preliminary Hearing on the basis of the evidence presented by the Milan Prosecutor at the preliminary hearing. In September 2018, the Judge convicted these defendants and sentenced them both to four-year detention terms and the disgorgement of profits amounting to approximately €100 million. In December 2018, the Judge for the Preliminary Hearing filed a written opinion setting forth the basis for these rulings. The defendants filed an appeal against this sentence.

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 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 commencementexpenses 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 billion 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.

~~(iv) 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 U.S. authorities (SEC and DoJ). In April 2018, the Public Prosecutor of Milan served Eni SpA with a further request for documentation and notified an 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.

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In December 2018 and subsequently in May and September 2019, Eni was notified by the Public Prosecutor of Milan 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 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, 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. The report resulting from this review was brought to the attention of the Public Prosecutor and the relevant US authorities (SEC and DoJ).

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 that 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 accusation is based on the allegations that the wife of the Company’s CEO retained a shareholding of the above-mentioned holding company over 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.

In November 2019, following the notification of further investigative documents, the Board of Statutory Auditors, the Control and Risk Committee and the Watch Structure of Eni asked the 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 February 2020, still of a preliminary nature and subject to modifications and follow-up, updates the conclusions reached by the first report and indicated that: (i) it is probable that the CEO’s wife held a shareholding in the Petroserve Group for a few years starting from 2009 until 2012 and in any case no later than the date the CEO was appointed Board member; (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.

~~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 three 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. On June 24, 2019, a settlement agreement was signed between Eni and the Customs Agency, involving the determination of the excise tax of €73 thousand and the reimbursement to Eni of the exceeding amounts paid while the judgment was pending. Consequently, an application to cease the dispute was presented to the Tax Commission. (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 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

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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 the course of 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 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.

In April 2018 as part of the administrative proceeding intended to collect taxes allegedly unpaid by Eni, the tax police of Rome based on the findings of the investigations performed by the prosecutors of Frosinone, Prato and Rome issued a statement of objection against the Company claiming the missed payment of excise taxes due for the years 2008 up to 2017 for €34 million, as well as the related higher corporate profits before income taxes leading to the claim of additional taxes for €22 million related to income taxes and VAT. The Custom Agency that is in charge of issuing the notice of payment may also impose a fine and the recognition of interest expense. A part of the disputed amounts for excise taxes and other related taxes concerned the same litigation, which was successfully challenged by the Company following a recourse filed with the Tax Commission of Rome and in relation to which the Company agreed upon an extrajudicial transaction with the Tax Authorities.

Following the documentation presented by the company, the Customs Agency determined the excise tax due in the amount of €8 million by issuing the payment notices in July 2019. Furthermore, the Agency estimated €6 million of other related taxes. The Company has paid the amounts determined by the Agency.

~~(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,

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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.

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. 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 concerns 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 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. Moreover, further procedural documentation became available following requests to review the aforementioned decree. The Board of Statutory Auditors, the Control Committee and the Watch Structure have instructed the same consultants appointed in 2018 to examine the aforementioned documentation, in order to review and summarize the facts underlying those allegations, as well as other factual elements and conduct to be examined in depth relating to the existence of any substantial issue or possible deficiency in the internal control and risk management system and in the organization and risk management model pursuant to Legislative Decree No. 231/01. The consultant’s activities are ongoing.

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~~(iii) Eni SpA — Public Prosecutor of Milan — Insider trading.~~promptly provided. In March 2019, a request for extending certain investigations was notified to Eni’s Chief Upstream Officer by the public prosecutor office of Milan. The commencement of those investigation 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.

~~4. Tax proceedings~~

~~(i) Dispute for omitted payment of a property tax for some oil offshore platforms located in territorial waters.~~ A Third Instance Court in Italy with a ruling issued in 2016 established that oil&gas offshore platforms located within territorial boundaries were subject to a property tax, resolving a dispute that has been in progress for about a decade in favor of local authorities. Eni was a party to many of these disputes and has entered into settlement transactions with various local authorities. Currently, a risk provision €17 million has been set aside in the consolidated financial statements for the remaining pending litigations.

The Third Instance Court ruling applied to the legislation in force until 2015. Since 2016 the regulatory framework has 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. To clarify the effects of this scope limitation of the property tax relating to above-mentioned offshore platforms, in 2016 the Italian association of oil&gas producers submitted a question to the Italian Finance Department. The 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/DF of June 1, 2016).

The ruling of the Department of Finance, however, is not binding for local authorities with taxing powers and three of these have issued assessment notices for 2016 and subsequent years. The Company has challenged these notices in legal proceedings. To date two first instance judgments have been issued, one in favor of the Company and one against. A second instance judgement has also been issued with results unfavorable to the Company. Of the two unfavorable outcomes, only one applies penalties. One of the two unfavorable judgements concerns the dispute with the municipality of Ravenna for the years 2016 and 2017, that judgement confirmed the assessment made by the municipality for a total tax of €19 million, in addition to the penalties applicable by law.

Based on the resolution of the Department of Finance in 2016, Eni believes that the scope limitation of the tax property enacted in 2016 applies to offshore platforms located within territorial boundaries and based on this the Company intends to continue to contest the assessment. No risk provisions have been accrued in the consolidated financial statements.

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) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration.~~ In January 2013, the Italian airline company Alitalia summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to seek a compensation for alleged damages caused by alleged anti-competitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a decision rendered by the Italian Antitrust Authority in June 2006. The antitrust decision accused Eni and another five petroleum companies of anti-competitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. In June 2019 the lawsuit was settled between all the involved parties. The amount transacted by Eni was previously accrued in the financial statements.

~~(ii) Eni SpA — Public Prosecutor’s Office of Rome — Criminal Procedure No. 2711/2019 — VAT returns.~~ On September 16, 2019, a notice of extension of the preliminary investigations was notified to the former CEO and the current CEO of Eni, in relation to the tax crime referred to in art. 4 of Legislative

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Decree 74/2000 (unfaithful tax statement). From the first investigations carried out by the defense attorney, the allegations referred to the criminal proceedings on fuel excise taxes, disclosed in the previous section and derived from the alleged taxes due on the higher profit before taxation ascertained as a result of evading the owed amounts of excise taxes for fiscal years from 2011 to 2014. As a result of the defensive activities carried out and due to the transaction carried out with the Customs and Revenue Agency, in November 2019 the Prosecutor filed a request to dismiss the proceedings and on December 2, 2019 the Court of Rome issued an order of dismissal.

~~(iii) Eni’s arbitration with GasTerra~~. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for the gas supplied in the 2012 – 2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. The arbitration award dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considered that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra claimed an additional amount to be paid by Eni which corresponded to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, did not agree with GasTerra’s interpretation and considered GasTerra’s claim groundless. However, GasTerra, based on its own interpretation, commenced an arbitration and obtained from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV for the alleged receivable due by Eni (equal to €1.01 billion). With respect to the interim seizure measure obtained by GasTerra, Eni offered to GasTerra, who in turn accepted, a bank guarantee of the same amount of the GasTerra claim. On July 8, 2019, the Tribunal issued an award concluding the first phase of the procedure by which it decided, in particular, that the provisional price mentioned above continued to apply in the 2012 – 2015 period, and that therefore GasTerra was not entitled to any price adjustment, so the invoices issued after the rendering of the award in 2016 were invalid. The Tribunal referred to the second phase of the arbitral procedure the quantification of Eni’s claims for damages against GasTerra. On July 24, 2019, upon Eni’s request and GasTerra consent, the bank guarantee for €1.01 billion was terminated. GasTerra has reserved its rights of appeal.

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. ~~As a compensation for mineral~~In respect of the mining concessions received, Eni pays royalties ~~and taxes~~ in accordance with ~~local~~

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the tax ~~legislation.~~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 offor 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

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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 ~~subjected~~subject to emission trading a lower assignment of emission permits ~~respect~~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 ~~2019,~~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 ~~19.30~~17.32 million tonnes, Eni was awarded free emission allowances of ~~7.73~~6.84 million tonnes, determining a deficit of ~~11.57~~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		Gas & Power		Refining & Marketing and Chemical		Corporate and Other activities		Total		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		38,160		21,017		205		69,881		10,499		9,230		41,976		7,972		204		69,881
Products sales and service revenues
Sales of crude oil		3,505		17,334		27				20,866		3,505				17,361						20,866
Sales of oil products		1,189		3,000		16,615				20,804		1,189				19,615						20,804
Sales of natural gas and LNG		5,454		12,468						17,922		5,454		8,881		214		3,373				17,922
Sales of petrochemical products				316		3,772		22		4,110						4,088				22		4,110
Sales of other products		68		2,502		16		7		2,593		68				16		2,503		6		2,593
Services		283		2,540		587		176		3,586		283		349		682		2,096		176		3,586
Total		10,499		38,160		21,017		205		69,881		10,499		9,230		41,976		7,972		204		69,881
Transfer of goods/services
Goods/Services transferred in a specific moment		9,946		38,047		20,768		87		68,848		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		553		113		249				118		1,033

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(€ million) Exploration
& Production Gas & Power Refining &
Marketing and
Chemical Corporate and
Other activities Total
2018
Sales from operations 9,943 43,109 22,594 176 75,822
Products sales and service revenues
Sales of crude oil 3,982 18,471 22,453
Sales of oil products 1,133 4,053 17,213 22,399
Sales of natural gas and LNG 4,554 15,088 19,642
Sales of petrochemical products 762 4,777 35 5,574
Sales of other products 27 2,363 20 11 2,421
Services 247 2,372 584 130 3,333
Total 9,943 43,109 22,594 176 75,822
Transfer of goods/services
Goods/Services transferred in a specific moment 9,676 42,979 22,535 106 75,296
Goods/Services transferred over a period of time 267 130 59 70 526
2017
Sales from operations 7,131 39,846 19,771 171 66,919
Products sales and service revenues
Sales of crude oil 2,431 17,693 17 20,141
Sales of oil products 1,030 3,930 14,615 19,575
Sales of natural gas and LNG 3,470 11,643 15,113
Sales of petrochemical products 147 4,591 32 4,770
Sales of other products 14 2,021 21 12 2,068
Services 186 4,412 527 127 5,252
Total 7,131 39,846 19,771 171 66,919

(€ million) 2019 2018
Revenues associated with contract liabilities at the beginning of the period 747 342
Revenues associated with performance obligations totally or partially satisfied in previous years 10 11


(€ 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 ~~geographic area.~~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) 2019 2018 2017
Gains from sale of assets and businesses 152 454 3,288
Other proceeds 1,008 662 770
1,160 1,116 4,058

~~In 2019, gains from the sale of assets and businesses related for €146 million to assets of the Exploration & Production segment.~~

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In 2018, gains from the sale of assets and businesses related to the divestment of a 10% stake in the Zohr project for €428 million. In 2017, the amount related to the divestment of a 25% stake in natural gas-rich Area 4 offshore Mozambique (€1,985 million) and of a 40% stake in the Zohr project (€1,281 million).


(€ 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 ~~€368~~€357 million (€368 million in 2019) related to the recovery of the cost share of right-of-use assets pertaining to partners of ~~non-incorporated~~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)	2019		2018		2017		2020		2019		2018
Production costs - raw, ancillary and consumable materials and goods		36,272		41,125		35,907		21,432		36,272		41,125
Production costs - services		11,589		10,625		12,228		9,710		11,589		10,625
Lease expense and other		1,478		1,820		1,684		876		1,478		1,820
Net provisions for contingencies		858		1,120		886		349		858		1,120
Charges for price variation on overliftling and underlifting operations						145
Other expenses		879		1,130		931		1,317		879		1,130
		51,076		55,820		51,781		33,684		51,076		55,820
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(197)		(192)		(224)		(128)		(197)		(192)
- capitalized direct costs associated with self-constructed assets - intangible assets		(5)		(6)		(9)		(5)		(5)		(6)
		50,874		55,622		51,548		33,551		50,874		55,622

Purchase, services and other charges ~~include~~included geological and geophysical costs of exploration activities for ~~€275~~€196 million (€~~287~~275 million and ~~€273~~€287 million in ~~2018~~2019 and ~~2017,~~2018, respectively). In 2018, ~~and 2017,~~ the item included operating leases for €872 ~~million and €1,022 million, respectively.~~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 ~~€194~~€157 million (€~~197~~194 million and ~~€185~~€197 million in ~~2018~~2019 and ~~2017,~~2018, respectively).

Royalties on the extraction rights of hydrocarbons amounted to ~~€1,183~~€673 million (€~~1,043~~1,183 million and ~~€674~~€1,043 million in ~~2018~~2019 and ~~2017,~~2018, respectively).

Additions to provisions net of reversal of unused provisions mainly related to net ~~addition~~additions for litigations amounting to €76 million (net additions of €60 million ~~(net provisions of~~and €101 million in 2019 and ~~€375 million in~~ 2018, ~~and 2017,~~ respectively) and net ~~additions~~reversals for environmental liabilities amounting to €15 million (net additions of €329 million ~~(net provisions of~~and €266 million in 2019 and ~~€200 million in~~ 2018, ~~and 2017,~~ 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 ~~geographic~~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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~~Payroll and related costs~~

(€ million) 2019 2018 2017
Wages and salaries 2,417 2,409 2,447
Social security contributions 449 448 441
Cost related to employee benefit plans 85 220 113
Other costs 213 170 162
3,164 3,247 3,163
less:
- capitalized direct costs associated with self-constructed assets - tangible assets (152) (142) (202)
- capitalized direct costs associated with self-constructed assets - intangible assets (16) (12) (10)
2,996 3,093 2,951

Other costs comprised provisions for redundancy incentives of €45 million (€37 million and €18 million in 2018 and 2017, respectively) and costs for defined contribution plans of €99 million (€95 million and €90 million in 2018 and 2017, respectively).

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)	2019				2018				2017				2020				2019				2018
(number)	Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations
Senior managers		1,014		16		999		17		995		17		993		17		1,014		16		999		17
Junior managers		9,267		77		9,095		84		9,089		98		9,280		73		9,267		77		9,095		84
Employees		15,945		361		16,220		361		16,721		371		15,995		349		15,945		361		16,220		361
Workers		4,910		287		5,259		283		5,659		285		4,780		287		4,910		287		5,259		283
		31,136		741		31,573		745		32,464		771		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~~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.~~plan 2017-2019 and 20 million in service of the plan 2020-2022.

The Long-Term Monetary Incentive ~~Plan 2017-2019 provides~~plans provide for three annual awards ~~for the years 2017,~~(2017, 2018 and 2019 and is2020, 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 ~~Plan provides~~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 ~~this incentive falls~~these incentives fall within the category of employee compensation, in accordance with IFRS, the cost of the ~~plan~~plans is determined based on the fair value of the financial instruments awarded to the beneficiaries and the number of shares that ~~will be~~are granted at the end of the vesting period; the cost is accruing along the vesting period.

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~~The~~With reference to the 2017-2019 Plan, the number of shares that will be granted at the end of the vesting period ~~is conditioned~~will depend: (i) for a 50%, on ~~a 50-50 basis to actual results of two performance parameters against preset targets: (i) a~~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 (“~~Peers~~Peer Group”)3729 and the TSR of their corresponding stock exchange market3830; (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

29

The group consists of the following oil companies:Apache, BP, Chevron, ConocoPhillips, Equinor, ExxonMobil, Marathon Oil, Occidental, Royal Dutch Shell and Total.

30

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 1,759,273~~was: (i) 2,922,749 shares in ~~2019, 1,517,975 in 2018 and 1,719,061 in 2017; the~~2020, with a weighted average fair value of ~~the~~€4.67 per share; (ii) 1,759,273 shares ~~at the same date was~~in 2019, with a weighted average fair value of €9.88 per ~~share~~share; (iii) 1,517,975 shares in ~~2019,~~2018, with a weighted average fair value of €11.73 per ~~share in 2018 and €7.99 per share in 2017.~~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)~~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 ~~(€13.714~~(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; €13.81 per share in 2017)~~2018), reduced by dividends expected along the vesting period ~~(6.1%~~(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; 5.8% of the share price at vesting date in 2017)~~2018), considering the volatility of the stock ~~(19%~~(between 41% and 44% in relation to the 2020 award; 19% for attribution 2019; 20% for attribution ~~2018; 25% for attribution 2017)~~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 ~~2019,~~2020, the costs related to the long-term monetary incentive plan, ~~2017 – 2019,~~ recognized as a component of the payroll cost, amounted to €9€7 million (€59 million in ~~2018; €0.4~~2019; €5 million in ~~2017)~~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)	2019		2018		2017		2020		2019		2018
Wages and salaries		28		27		25		30		28		27
Post-employment benefits		2		2		2		2		2		2
Other long-term benefits		12		10		9		12		12		10
Indemnities upon termination of employment		12				7		21		12
		54		39		43		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 ~~€14.5 million for 2019,~~ 2018, ~~and 2017,~~ respectively. Compensation of Statutory Auditors amounted to €0.571 million, €0.613 million and €0.604 million in 2020, 2019 and ~~€0.760 million in 2019,~~ 2018, ~~and 2017,~~ 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.

37

~~The group consists of the following oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and Total.~~

38

~~The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition.~~

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30 Finance income (expense)


(€ million)	2019		2018		2017			2020		2019		2018
Finance income (expense)
Finance income		3,087		3,967		3,924	��		3,531		3,087		3,967
Finance expense		(4,079)		(4,663)		(5,886)			(4,958)		(4,079)		(4,663)
Net finance income (expense) from financial assets held for trading		127		32		(111)			31		127		32
Income (expense) from derivative financial instruments		(14)		(307)		837			351		(14)		(307)
		(879)		(971)		(1,236)			(1,045)		(879)		(971)

The analysis of finance income (expense) was as follows:


(€ million)	2019		2018		2017		2020		2019		2018
Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(618)		(565)		(638)		(517)		(618)		(565)
Net finance income (expense) on financial assets held for trading		127		32		(111)		31		127		32
Interest and other expense due to banks and other financial institutions		(122)		(120)		(113)		(102)		(122)		(120)
Interest on lease liabilities		(378)						(347)		(378)
Interest from banks		21		18		12		10		21		18
Interest and other income on financial receivables and securities held for non-operating purposes		8		8		16		12		8		8
		(962)		(627)		(834)		(913)		(962)		(627)
Exchange differences		250		341		(905)		(460)		250		341
Income (expense) from derivative financial instruments		(14)		(307)		837		351		(14)		(307)
Other finance income (expense)
Interest and other income on financing receivables and securities held for operating purposes		112		132		128		97		112		132
Capitalized finance expense		93		52		73		73		93		52
Finance expense due to the passage of time (accretion discount) (a)		(255)		(249)		(264)		(190)		(255)		(249)
Other finance income (expense)		(103)		(313)		(271)		(3)		(103)		(313)
		(153)		(378)		(334)		(23)		(153)		(378)
		(879)		(971)		(1,236)		(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 ~~income (expense) from~~ derivative financial ~~instruments~~income (expense) is disclosed in note 23 — Derivative financial instruments and hedge accounting.

~~Operating expenses~~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 ~~geographic~~geographical area.

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Other gain (loss) from investments


(€ million)	2019		2018		2017		2020		2019		2018
Dividends		247		231		205		150		247		231
Net gain (loss) on disposals		19	��	22		163				19		22
Other net income (expense)		15		910		(33)		(75)		15		910
		281		1,163		335		75		281		1,163

Dividend income primarily related to Nigeria LNG Ltd for ~~€186~~€113 million and to Saudi European Petrochemical Co for €28 million (€186 million, €46 million ~~(€187~~in 2019 and €187 million and €35 million in ~~2018 and €167 million and €21 million in 2017, respectively)~~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)	2019		2018		2017		2020		2019		2018
Current taxes:
- Italian subsidiaries		347		301		712		199		347		301
- subsidiaries of the Exploration & Production segment - outside Italy		4,729		4,906		3,167		1,517		4,729		4,906
- other subsidiaries - outside Italy		152		163		142		84		152		163
		5,228		5,370		4,021		1,800		5,228		5,370
Net deferred taxes:
- Italian subsidiaries		599		130		(464)		672		599		130
- subsidiaries of the Exploration & Production segment - outside Italy		(172)		497		(162)		73		(172)		497
- other subsidiaries - outside Italy		(64)		(27)		72		105		(64)		(27)
		363		600		(554)		850		363		600
		5,591		5,970		3,467		2,650		5,591		5,970

Current income taxes payable by Italian subsidiaries referred to foreign taxes for ~~€137~~€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 ~~2018~~2019 and ~~2017)~~2018) and the effective tax charge is the following:


(€ million)	2019		2018		2017		2020		2019		2018
Profit (loss) before taxation		5,746		10,107		6,844		(5,978)		5,746		10,107
Tax rate (IRES) (%)		24.0		24.0		24.0		24.0		24.0		24.0
Statutory corporation tax charge (credit) on profit or loss		1,379		2,426		1,643		(1,435)		1,379		2,426
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy		2,934		3,096		1,882		1,980		2,934		3,096
- impact pursuant to the write-down of deferred tax assets and recalculation of tax rates		938		261		(96)
- 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		147		(24)		(1)		(30)		147		(24)
- impact pursuant to foreign tax effects of italian entities		105		46		54
- effect due to the tax regime provided for intercompany dividends		65		47		1
- Italian regional income tax (IRAP)		25		50		77
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009						61
- effect due to non-taxable gains/losses on sales of investments				(1)		(177)
- other adjustments		(2)		69		23		39		(2)		68
		4,212		3,544		1,824		4,085		4,212		3,544
Effective tax charge		5,591		5,970		3,467		2,650		5,591		5,970

The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for ~~€2,934~~€1,777 million (€~~3,014~~2,934 million and ~~€1,811~~€3,014 million in ~~2018~~2019 and in ~~2017,~~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.

~~The average number of ordinary shares used for the calculation of the basic~~Diluted earnings ~~per share in 2019 was 3,592,249,603 (3,601,140,133 in 2018 and 2017).~~

~~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, ~~2019,~~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 ~~plan.~~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:

2019 2018 2017
Weighted average number of shares used for basic earnings per share 3,592,249,603 3,601,140,133 3,601,140,133
Potential shares to be issued for ILT incentive plan 2,251,406 2,782,584 1,691,413
Weighted average number of shares used for diluted earnings per share 3,594,501,009 3,603,922,717 3,602,831,546
Eni’s net profit (€million) 148 4,126 3,374
Basic earnings per share (€ per share) 0.04 1.15 0.94
Diluted earnings per share (€ per share) 0.04 1.15 0.94

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		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)	2019		2018		2017		2020		2019		2018
Revenues related to exploration activity and evaluation		34		17		9				34		17
Exploration activity and evaluation costs
Exploration activity and evaluation costs:
- write-off of exploration and evaluation costs		214		93		252		314		214		93
- costs of geological and geophysical studies		275		287		273		196		275		287
Exploration expense for the year		489		380		525		510		489		380
Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs		1,031		1,081		995		888		1,031		1,081
Tangible assets: capitalized exploration and evaluation costs		1,563		1,267		1,371		1,341		1,563		1,267
Total tangible and intangible assets		2,594		2,348		2,366		2,229		2,594		2,348
Provision for decommissioning related to exploration activity and evaluation		109		77		81		93		109		77
Exploration expenditure (net cash used in investing activivties)		586		463		442		283		586		463
Geological and geophysical costs (cash flow from operating activities)		275		287		273		196		275		287
Total exploration effort		861		750		715		479		861		750

35 Segment information and information by geographic area

Segment information

Effective July 1, 2020, Eni’s ~~segmental reporting reflects~~management redesigned the ~~Group’s operating segments, whose results are regularly reviewed by~~macro-organizational structure of the ~~chief operating decision maker (the CEO) to make decisions about resources to be allocated to each segment and to assess segment performance.~~

~~Segment performance is evaluated based on operating profit or loss. Other segment information presented~~Group, in line with its new long-term strategy, disclosed in February 2020 to the ~~CEO include segment revenues~~market and ~~directly attributable assets and liabilities.~~

~~As of December 31, 2019, Eni had~~aimed at transforming the ~~following reportable segments:~~

•

~~Exploration & Production: engages~~Company into a leader in the ~~research, development and production of crude oil and natural gas, including projects to build and operate liquefaction plants of LNG;~~

•

~~Gas & Power:~~ ~~engages in supply and marketing of natural gas at wholesale and retail markets, supply and marketing of LNG and supply,~~ production and marketing of ~~power at retail and wholesale markets. Gas & Power~~decarbonized energy products.

The new organization is ~~also engaged in supply and marketing of crude oil and oil products targeting~~based on two new General Departments:

•

Natural Resources, to build up the ~~operational requirements~~value of Eni’s ~~refining~~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 ~~energy commodity trading (including crude~~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 ~~oil products, power, emission allowances, etc.~~wholesale via pipeline and LNG. In addition, it will include forests conservation (REDD+) ~~targeting to both hedge~~ and ~~stabilize the Group’s industrial and commercial margins according to an integrated view and to optimize margins.~~

•

~~Refining & Marketing and Chemical: engages in the manufacturing, supply and distribution and marketing activities of oil products and chemical products.~~carbon storage projects. The results of the Chemicals business have been aggregated to those of the Refining & Marketing business in a single reportable segment, because these two operating segments exhibit similar economic characteristics.

•

~~Corporate and Other activities~~: include the costs of the Group HQ functions which provide services to the operating subsidiaries, comprising holding, financing and treasury, IT, HR, real estate, legal assistance, captive insurance, as well as the results of the Group environmental clean-up and remediation activities performed by the subsidiarycompany Eni Rewind ~~SpA (former Syndial SpA). The Energy Solutions Department, which engages~~(environmental activities), will also be consolidated in developing the renewable energy business, is an operating segment, which is reported within Corporate and Other activities because it does not meet the materiality threshold set by IFRS 8 for separate segment reporting.this General Department.

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~~Information~~•

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 isreporting (IFRS 8), the new reportable segments of Eni, substantially confirming the pre-existing setup, are identified as follows:

(€ million) Exploration &
Production Gas & Power Refining &
Marketing
and Chemical 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
Net provisions for contingencies 97 232 273 307 (51) 858
Depreciation and amortization (7,060) (447) (485) (146) 32 (8,106)
Impairments of tangible and intangible assets and right-of-use assets (1,347) (83) (1,127) (13) (2,570)
Reversals of tangible and intangible assets 130 46 205 1 382
Write-off of tangible and intangible assets (292) (1) (6) (1) (300)
Share of profit (loss) of equity-accounted investments 7 (11) (63) (21) (88)
Identifiable assets(a)
68,915 9,176 12,336 1,860 (492) 91,795
Unallocated assets(b)
31,645
Equity-accounted investments 4,108 487 3,107 1,333 9,035
Identifiable liabilities(c)
20,164 7,852 4,599 3,927 (141) 36,401
Unallocated liabilities(d)
39,139
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets 6,996 230 933 231 (14) 8,376
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
Net provisions for contingencies 235 53 274 579 (21) 1,120
Depreciation and amortization (6,152) (408) (399) (59) 30 (6,988)
Impairments of tangible and intangible assets (1,025) (56) (193) (18) (1,292)
Reversals of tangible and intangible assets 299 127 426
Write-off of tangible and intangible assets (97) (1) (2) (100)
Share of profit (loss) of equity-accounted investments 158 9 (67) (168) (68)
Identifiable assets(a)
63,051 9,989 11,692 1,171 (420) 85,483
Unallocated assets(b)
32,890
Equity-accounted investments 4,972 494 275 1,303 7,044
Identifiable liabilities(c)
18,110 8,314 4,319 4,072 (275) 34,540
Unallocated liabilities(d)
32,760
Capital expenditure in tangible and intangible assets 7,901 215 877 143 (17) 9,119
2017
Sales from operations including intersegment sales 19,525 50,623 22,107 1,462
Less: intersegment sales (12,394) (10,777) (2,336) (1,291)
Sales from operations 7,131 39,846 19,771 171 66,919
Operating profit 7,651 75 981 (668) (27) 8,012
Net provisions for contingencies 479 (20) 182 245 886
Depreciation and amortization (6,747) (345) (360) (60) 29 (7,483)
Impairments of tangible and intangible assets (650) (56) (131) (25) (862)
Reversals of tangible and intangible assets 808 202 77 1,087
Write-off of tangible and intangible assets (260) (2) (1) (263)
Share of profit (loss) of equity-accounted investments (99) (10) (57) (101) (267)
Identifiable assets(a)
66,661 11,058 11,599 1,108 (610) 89,816
Unallocated assets(b)
25,112
Equity-accounted investments 1,234 509 321 1,447 3,511
Identifiable liabilities(c)
17,273 8,851 4,005 4,053 (306) 33,876
Unallocated liabilities(d)
32,973
Capital expenditure in tangible and intangible assets 7,739 142 729 87 (16) 8,681

•

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.

•

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.

•

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/optimising the margins of the electricity.

•

Corporate and Other activities: includes the main business support functions, in particular holding, central treasury, IT, human resources, real estate services, captive insurance activities, research and development, new technologies, business digitalization and the environmental 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 directly associated with the generation of operating profit.~~

~~(b)~~

~~Include assets not directly associated with the generation of operating profit.~~

~~(c)~~

~~Include~~ assets/liabilities directly associated with the generation of operating profit.

~~(d)~~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.

~~F-113~~F-115

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~~Information~~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		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		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		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		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		1,424		267		538		534		1,782		4,533		41		9,119
2017
Identifiable assets(a)		18,449		7,706		6,160		4,406		16,527		35,385		1,183		89,816
Capital expenditure in tangible and intangible assets		1,090		316		387		278		898		5,699		13		8,681

(a)

Include assets directly associated with the generation of operating profit.

Sales from operations by geographical area of destination


(€ million)	2019		2018		2017		2020		2019		2018
Italy		23,312		25,279		21,925		14,717		23,312		25,279
Other European Union		18,567		20,408		19,791		9,508		18,567		20,408
Rest of Europe		6,931		7,052		5,911		8,191		6,931		7,052
Americas		3,842		5,051		5,154		2,426		3,842		5,051
Asia		8,102		9,585		7,523		4,182		8,102		9,585
Africa		8,998		8,246		6,428		4,842		8,998		8,246
Other areas		129		201		187		121		129		201
		69,881		75,822		66,919		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:

~~(a)~~a)

Purchase/supply of goods and services and the provision of financing to joint ventures, associates and non-consolidated subsidiaries;

~~(b)~~b)

Purchase/supply of goods and services to entities controlled by the Italian Government;

~~(c)~~c)

Purchase/supply of goods and services to companies related to Eni SpA through members of the Board of Directors. Most of these transactions are exempt from the application of the Eni internal procedure “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or standard conditions, or because they fall below the materiality threshold provided for by the procedure. The solely non-exempted ~~transaction,~~transactions, that ~~was~~were positively examined and valued in application of the procedure, ~~concerned~~concerned: (i) the ~~remote monitoring~~revision of ~~cars in the “enjoy” initiative (for an amount of about €1 million) conducted~~a service contract connected to network infrastructures with Vodafone Italia ~~SpA~~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 ~~of a member~~two members of the Board of Directors; ~~and~~

~~(d)~~d)

contributions to non-profit entities correlated to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation, established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as scientific and technological

F-116

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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.

~~F-114~~

~~TABLE OF CONTENTS~~

Transactions and balances with related parties

(€ million)	December 31, 2019						2019						December 31, 2020						2020
Name	Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income		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				6		52						201
Angola LNG Supply Services Llc						181												165
Coral FLNG SA		15				1,168		71						6				1,079		49
Gas Distribution Company of Thessaloniki - Thessaly SA				13						53						13						52
Saipem Group		75		227		510		27		503				87		254		509		18		350
Karachaganak Petroleum Operating BV		33		198				1		1,134				25		141						816
Mellitah Oil & Gas BV		57		171				3		365				54		250				2		156
Petrobel Belayim Petroleum Co		50		1,130				7		1,590				65		467						556
Societa Oleodotti Meridionali SpA														3		399				20		15
Société Centrale Electrique du Congo SA														48						57
Unión Fenosa Gas SA		8		1		57		1		6		63		11		4		57		9				(3)
Vår Energi AS		32		143		482		63		1,481		(64)		39		190		456		85		1,126		(118)
Other(*)		106		29		1		112		87				72		24		1		66		167
		379		1,983		2,399		285		5,448		(1)		416		1,794		2,267		306		3,439		(121)
Unconsolidated entities controlled by Eni
Eni BTC Ltd						180												165
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		101		1		3		14						112		1		1		11
Other		5		25		14		6		18				5		23		10		4		9
		106		26		197		20		18				117		24		176		15		9
		485		2,009		2,596		305		5,466		(1)		533		1,818		2,443		321		3,448		(121)
Entities controlled by the Government
Enel Group		185		284				105		602		(8)		104		165				51		551		86
Italgas Group		3		154				1		677				1		177				3		714
Snam Group		278		229				71		1,208				189		211				45		1,012
Terna Group		40		45				171		223		17		46		62				152		225		8
GSE - Gestore Servizi Energetici		26		24				549		468		11		52		37				586		309		40
Other		10		19				12		35
Other (*)														8		49				20		63
		542		755				909		3,213		20		400		701				857		2,874		134
Other related parties		2		3				5		37				1		4				2		53
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»		75		74				33		457				87		52				19		262
		1,104		2,841		2,596		1,252		9,173		19		1,021		2,575		2,443		1,199		6,637		13

(*)

~~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.

~~F-115~~F-117

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(€ million)	December 31, 2017						2017						December 31, 2019						2019
Name	Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income		Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income
Joint ventures and associates
Agiba Petroleum Co		1		83						142				3		71						229
Angola LNG Supply Services Llc																		181
Coral FLNG SA		20		4		1,094		28						15				1,168		71
Gas Distribution Company of Thessaloniki - Thessaly SA																13						53
Saipem Group														75		227		510		27		503
Karachaganak Petroleum Operating BV		36		121						951				33		198				1		1,134
Mellitah Oil & Gas BV		5		220				2		495				57		171				3		365
Petrobel Belayim Petroleum Co		86		1,205				8		3,168				50		1,130				7		1,590
Saipem Group		63		76		7,270		44		450
Unión Fenosa Gas SA						57		202		3		28		8		1		57		1		6		63
Vår Energi AS														32		143		482		63		1,481		(64)
Other(*)		84		22				128		140				106		29		1		112		87
		295		1,731		8,421		412		5,349		28		379		1,983		2,399		285		5,448		(1)
Unconsolidated entities controlled by Eni
Eni BTC Ltd						169												180
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		77		1		5		7						101		1		3		14
Other		20		23		7		7		14				5		25		14		6		18
		97		24		181		14		14				106		26		197		20		18
		392		1,755		8,602		426		5,363		28		485		2,009		2,596		305		5,466		(1)
Entities controlled by the Government
Enel Group		123		187				164		622		285		185		284				105		602		(8)
GSE - Gestore Servizi Energetici		69		219				702		506		2
Italgas Group		14		180		1		18		681				3		154				1		677
Snam Group		187		351				85		1,221				278		229				71		1,208
Terna Group		35		31				154		212		15		40		45				171		223		17
Other(*)		50		21				16		38		1
GSE - Gestore Servizi Energetici														26		24				549		468		11
Other														10		19				12		35
		478		989		1		1,139		3,280		303		542		755				909		3,213		20
Other related parties		1		2				1		25				2		3				5		37
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»		39		145				42		530				75		74				33		457
		910		2,891		8,603		1,608		9,198		331		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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TABLE OF CONTENTS

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~~Thessaloniki — Thessaly SA;

•

engineering, construction and drilling services by ~~the~~ 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;

•

~~a guarantee~~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 ~~gas and fair value~~the realized part of ~~derivative financial instruments;~~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).

~~F-116~~

~~TABLE OF CONTENTS~~

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 ~~the basis of~~ 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.~~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 ~~€30~~€40 million; and

•

contributions and service provisions to Eni Enrico Mattei Foundation for €6€5 million and to Eni Foundation for €1 million.

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Financing transactions and balances with related parties

(€ 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 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 49 25
Entities controlled by the Government
Enel Group 64
Other 8 2
72 2
964 661 1,664 115 283

(€ 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

~~F-117~~F-120

TABLE OF CONTENTS

(€ million)
December 31, 2017 2017
Name Receivables Payables Guarantees Gains Charges
Joint ventures and associates
Angola LNG Ltd 233
Coral South FLNG D MCC 1,334
Cardón IV SA 955 86
Shatskmorneftegaz Sarl 101 6
Société Centrale Electrique du Congo SA 66 43
Saipem Group 3 56 13
Coral FLNG SA 56 71
Other 48 49 2 14 1
1,226 95 1,625 190 1
Unconsolidated entities controlled by Eni
Servizi Fondo Bombole Metano SpA 60 9 1
Other(*) 1 52
61 61 1
Entities controlled by the Government
Other 8 3
8 3
1,287 164 1,625 191 4

~~(*)~~

~~Each individual amount included herein was lower than €50 million.~~

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, 2019 December 31, 2018
Total Related
parties Impact % Total Related
parties Impact %
Other current financial assets 384 60 15.63 300 49 16.33
Trade and other receivables 12,873 704 5.47 14,101 633 4.49
Other current assets 3,972 219 5.51 2,819 71 2.52
Other non-current financial assets 1,174 911 77.60 1,253 915 73.02
Other non-current assets 871 181 20.78 624 160 25.64
Short-term debt 2,452 46 1.88 2,182 661 30.29
Current portion of long-term lease liabilities 889 5 0.56
Trade and other payables 15,545 2,663 17.13 16,747 3,664 21.88
Other current liabilities 7,146 155 2.17 5,412 63 1.16
Long-term lease liabilities 4,759 8 0.17
Other non-current liabilities 1,611 23 1.43 1,475 23 1.56

~~F-118~~

~~TABLE OF CONTENTS~~

(€ 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:


	2019						2018						2017						2020						2019						2018
(€million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
(€ million)																			Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
Sales from operations		69,881		1,248		1.79		75,822		1,383		1.82		66,919		1,567		2.34		43,987		1,164		2.65		69,881		1,248		1.79		75,822		1,383		1.82
Other income and revenues		1,160		4		0.34		1,116		8		0.72		4,058		41		1.01		960		35		3.65		1,160		4		0.34		1,116		8		0.72
Purchases, services and other		(50,874)		(9,173)		18.03		(55,622)		(8,009)		14.40		(51,548)		(9,164)		17.78		(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		(432)		28		—		(415)		26		—		(913)						(226)		(6)		2.65		(432)		28		—		(415)		26		—
Payroll and related costs		(2,996)		(28)		0.93		(3,093)		(22)		0.71		(2,951)		(34)		1.15		(2,863)		(36)		1.26		(2,996)		(28)		0.93		(3,093)		(22)		0.71
Other operating income (expense)		287		19		6.62		129		319		—		(32)		331		—		(766)		13		—		287		19		6.62		129		319		—
Finance income		3,087		96		3.11		3,967		115		2.90		3,924		191		4.87		3,531		114		3.23		3,087		96		3.11		3,967		115		2.90
Finance expense		(4,079)		(36)		0.88		(4,663)		(283)		6.07		(5,886)		(4)		0.07		(4,958)		(26)		0.52		(4,079)		(36)		0.88		(4,663)		(283)		6.07

F-121

TABLE OF CONTENTS

Main cash flows with related parties are provided below:


(€ million)	2019		2018		2017		2020		2019		2018
Revenues and other income		1,252		1,391		1,608		1,199		1,252		1,391
Costs and other expenses		(6,869)		(5,210)		(5,360)		(5,789)		(6,869)		(5,210)
Other operating income (expense)		19		319		331
Other operating (expense) income								13		19		319
Net change in trade and other receivables and payables		(839)		683		391		(136)		(839)		683
Net interests		81		110		187		73		81		110
Net cash provided from operating activities		(6,356)		(2,707)		(2,843)		(4,640)		(6,356)		(2,707)
Capital expenditure in tangible and intangible assets		(2,332)		(2,768)		(3,838)		(842)		(2,332)		(2,768)
Net change in accounts payable and receivable in relation to investments		(339)		20		425		(370)		(339)		20
Change in financial receivables		(241)		(566)		298		(160)		(241)		(566)
Net cash used in investing activities		(2,912)		(3,314)		(3,115)		(1,372)		(2,912)		(3,314)
Change in financial and lease liabilities		(817)		16		(16)		164		(817)		16
Net cash used in financing activities		(817)		16		(16)		164		(817)		16
Total financial flows to related parties		(10,085)		(6,005)		(5,974)		(5,848)		(10,085)		(6,005)

The impact of cash flows with related parties consisted of the following:

2019 2018 2017
(€ million) Total Related
parties Impact
% Total Related
parties Impact
% Total Related
parties Impact
%
Net cash provided by operating activities 12,392 (6,356) — 13,647 (2,707) — 10,117 (2,843) —
Net cash used in investing activities (11,413) (2,912) 25.51 (7,536) (3,314) 43.98 (3,768) (3,115) 82.67
Net cash used in financing activities (5,841) (817) 13.99 (2,637) 16 — (4,595) (16) 0.35

~~F-119~~

~~TABLE OF CONTENTS~~


	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, ~~2019~~2020

The following section provides information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, ~~2019.~~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

~~25.76~~25.96

~~4.34~~4.37

~~1.70~~0.92

~~68.20~~68.75

~~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 100.00 100.00 F.C.
Eni Mediterranea Idrocarburi SpA Gela (CL) Italy EUR 5,200,000 Eni SpA 100.00 100.00 F.C.
Eni Mozambico SpA San Donato
Milanese (MI) Mozambique EUR 200,000 Eni SpA 100.00 100.00 F.C.
Eni Timor Leste SpA San Donato
Milanese (MI) East Timor EUR 6,841,517 Eni SpA 100.00 100.00 F.C.
Eni West Africa SpA San Donato
Milanese (MI) Angola EUR 10,000,000 Eni SpA 100.00 100.00 F.C.
EniProgetti SpA Venezia
Marghera (VE) Italy EUR 2,064,000 Eni SpA 100.00 100.00 F.C.
Floaters SpA San Donato
Milanese (MI) Italy EUR 200,120,000 Eni SpA 100.00 100.00 F.C.
Ieoc SpA San Donato
Milanese (MI) Egypt EUR 7,518,000 Eni SpA 100.00 100.00 F.C.
Società Petrolifera Italiana SpA San Donato
Milanese (MI) Italy EUR 13,877,600
Eni SpA
Third parties

99.96
0.04
99.96 F.C.

~~(*)~~

~~F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value~~

(#)

Company with shares quoted in the regulated market of Italy or of other EU countries

~~F-120~~

~~TABLE OF CONTENTS~~

~~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 100.00 100.00 F.C.
Agip Energy and Natural Resources (Nigeria) Ltd Abuja
(Nigeria) Nigeria NGN 5,000,000 Eni International BV
Eni Oil Holdings BV 95.00
5.00 100.00 F.C.
Agip Karachaganak BV Amsterdam
(Netherlands) Kazakhstan EUR 20,005 Eni International BV 100.00 100.00 F.C.
Agip Oleoducto de Crudos
Pesados BV
(in liquidation)
Amsterdam
(Netherlands) Ecuador EUR 20,000 Eni International BV 100.00 Co.
Burren Energy (Bermuda)
Ltd Hamilton
(Bermuda) United
Kingdom USD 12,002 Burren Energy Plc 100.00 100.00 F.C.
Burren Energy (Egypt) Ltd London
(United
Kingdom) Egypt GBP 2 Burren Energy Plc 100.00 Eq.
Burren Energy Congo Ltd Tortola
(British Virgin
Islands) Republic of
the Congo USD 50,000 Burren En.(Berm)Ltd 100.00 100.00 F.C.
Burren Energy India Ltd London
(United
Kingdom) United
Kingdom GBP 2 Burren Energy Plc 100.00 100.00 F.C.
Burren Energy Plc London
(United
Kingdom) United
Kingdom GBP 28,819,023 Eni UK Holding Plc
Eni UK Ltd 99.99
(..) 100.00 F.C.
Burren Shakti Ltd Hamilton
(Bermuda) United
Kingdom USD 213,138 Burren En. India Ltd 100.00 100.00 F.C.
Eni Abu Dhabi BV Amsterdam
(Netherlands) United Arab
Emirates EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni AEP Ltd London
(United
Kingdom) Pakistan GBP 13,471,000 Eni UK Ltd 100.00 100.00 F.C.
Eni Albania BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 Eq.
Eni Algeria Exploration BV Amsterdam
(Netherlands) Algeria EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Algeria Ltd Sàrl Luxembourg
(Luxembourg) Algeria USD 20,000 Eni Oil Holdings BV 100.00 100.00 F.C.
Eni Algeria Production BV Amsterdam
(Netherlands) Algeria EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Ambalat Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni America Ltd Dover, Delaware
(USA) USA USD 72,000 Eni UHL Ltd 100.00 100.00 F.C.
Eni Angola Exploration BV Amsterdam
(Netherlands) Angola EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Angola Production BV Amsterdam
(Netherlands) Angola EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Argentina Exploración
y Explotación SA Buenos Aires
(Argentina) Argentina ARS 24,136,336 Eni International BV
Eni Oil Holdings BV 95.00
5.00 100.00 F.C.

~~(*)~~

~~F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value~~

~~F-121~~

~~TABLE OF CONTENTS~~

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership %Equity
ratio
Consolidation
or valutation
method(*)

Eni Arguni I Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni Australia BV Amsterdam
(Netherlands) Australia EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Australia Ltd London
(United
Kingdom) Australia GBP 20,000,000 Eni International BV 100.00 100.00 F.C.
Eni Bahrain BV Amsterdam
(Netherlands) Bahrain EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni BB Petroleum Inc Dover,
Delaware
(USA) USA USD 1,000 Eni Petroleum Co Inc 100.00 100.00 F.C.
Eni BTC Ltd London
(United
Kingdom) United
Kingdom GBP 1 Eni International BV 100.00 Eq.
Eni Bukat Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni Bulungan BV
(in liquidation)
Amsterdam
(Netherlands) Indonesia EUR 20,000 Eni International BV 100.00 Co.
Eni Canada Holding Ltd Calgary
(Canada) Canada USD 1,453,200,001 Eni International BV 100.00 100.00 F.C.
Eni CBM Ltd London
(United
Kingdom) Indonesia USD 2,210,728 Eni Lasmo Plc 100.00 100.00 F.C.
Eni China BV Amsterdam
(Netherlands) China EUR 20,000 Eni International BV 100.00 100.00 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 1 Eni Lasmo Plc 100.00 100.00 F.C.
Eni Cyprus Ltd Nicosia
(Cyprus) Cyprus EUR 2,006 Eni International BV 100.00 100.00 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 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni East Sepinggan Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni Elgin/Franklin Ltd London
(United
Kingdom) United
Kingdom GBP 100 Eni UK Ltd 100.00 100.00 F.C.
Eni Energy Russia BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Exploration & Production Holding BV Amsterdam
(Netherlands) Netherlands EUR 29,832,777.12 Eni International BV 100.00 100.00 F.C.
Eni Gabon SA Libreville
(Gabon) Gabon XAF 13,132,000,000 Eni International BV 100.00 100.00 F.C.
Eni Ganal Ltd London
(United
Kingdom) Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 F.C.

~~(*)~~

~~F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value~~

F-122

TABLE OF CONTENTS

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

Eni Gas & Power LNG Australia BV Amsterdam
(Netherlands) Australia EUR 10,000,000 Eni International BV 100.00 100.00 F.C.
Eni Ghana Exploration and Production Ltd Accra
(Ghana) Ghana GHS 21,412,500 Eni International BV 100.00 100.00 F.C.
Eni Hewett Ltd Aberdeen
(United
Kingdom) United
Kingdom GBP 3,036,000 Eni UK Ltd 100.00 100.00 F.C.
Eni Hydrocarbons Venezuela Ltd London
(United
Kingdom) Venezuela GBP 8,050,500 Eni Lasmo Plc 100.00 100.00 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 100.00 100.00 F.C.
Eni Indonesia Ots 1 Ltd Grand Cayman
(Cayman Islands) Indonesia USD 1.01 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni International NA
NV Sàrl Luxembourg
(Luxembourg) United
Kingdom USD 25,000 Eni International BV 100.00 100.00 F.C.
Eni Investments Plc London
(United
Kingdom) United
Kingdom GBP 750,050,000 Eni SpA
Eni UK Ltd
99.99
(..)
100.00 F.C.
Eni Iran BV Amsterdam
(Netherlands) Iran EUR 20,000 Eni International BV 100.00 Eq.
Eni Iraq BV Amsterdam
(Netherlands) Iraq EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Ireland BV Amsterdam
(Netherlands) Ireland EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Isatay BV Amsterdam
(Netherlands) Kazakhstan EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni JPDA 03-13 Ltd London
(United
Kingdom) Australia GBP 250,000 Eni International BV 100.00 100.00 F.C.
Eni JPDA 06-105 Pty
Ltd Perth
(Australia) Australia AUD 80,830,576 Eni International BV 100.00 100.00 F.C.
Eni JPDA 11-106 BV Amsterdam
(Netherlands) Australia EUR 50,000 Eni International BV 100.00 100.00 F.C.
Eni Kenya BV Amsterdam
(Netherlands) Kenya EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Krueng Mane Ltd London
(United
Kingdom) Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni Lasmo Plc London
(United
Kingdom) United
Kingdom GBP 337,638,724.25 Eni Investments Plc
Eni UK Ltd
99.99
(..)
100.00 F.C.
Eni Lebanon BV Amsterdam
(Netherlands) Lebanon EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Liberia BV Amsterdam
(Netherlands) Liberia EUR 20,000 Eni International BV 100.00 Eq.
Eni Liverpool Bay Operating Co Ltd London
(United
Kingdom) United
Kingdom GBP 1 Eni UK Ltd 100.00 Eq.
Eni LNS Ltd London
(United
Kingdom) United
Kingdom GBP 80,400,000 Eni UK Ltd 100.00 100.00 F.C.
Eni Marketing Inc Dover, Delaware
(USA) USA USD 1,000 Eni Petroleum Co Inc 100.00 100.00 F.C.
Eni Maroc BV Amsterdam
(Netherlands) Morocco EUR 20,000 Eni International BV 100.00 100.00 F.C.

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

2

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

2

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

1

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

1

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

F-123

TABLE OF CONTENTS

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

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.
Eni Middle East Ltd London
(United
Kingdom) United
Kingdom GBP 1 Eni ULT Ltd 100.00 100.00 F.C.
Eni MOG Ltd
(in liquidation)
London
(United
Kingdom) United
Kingdom GBP 220,711,147.50 Eni Lasmo Plc
Eni LNS Ltd
99.99
(..)
100.00 F.C.
Eni Montenegro BV Amsterdam
(Netherlands) Montenegro EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Mozambique Engineering Ltd London
(United
Kingdom) United
Kingdom GBP 1 Eni Lasmo Plc 100.00 100.00 F.C.
Eni Mozambique LNG
Holding BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Muara Bakau BV Amsterdam
(Netherlands) Indonesia EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Myanmar BV Amsterdam
(Netherlands) Myanmar EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni North Africa BV Amsterdam
(Netherlands) Libya EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni North Ganal Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni Oil & Gas Inc Dover,
Delaware
(USA) USA USD 100,800 Eni America Ltd 100.00 100.00 F.C.
Eni Oil Algeria Ltd London
(United
Kingdom) Algeria GBP 1,000 Eni Lasmo Plc 100.00 100.00 F.C.
Eni Oil Holdings BV Amsterdam
(Netherlands) Netherlands EUR 450,000 Eni ULX Ltd 100.00 100.00 F.C.
Eni Oman BV Amsterdam
(Netherlands) Oman EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Pakistan Ltd London
(United
Kingdom) Pakistan GBP 90,087 Eni ULX Ltd 100.00 100.00 F.C.
Eni Pakistan (M) Ltd Sàrl Luxembourg
(Luxembourg) Pakistan USD 20,000 Eni Oil Holdings BV 100.00 100.00 F.C.
Eni Petroleum Co Inc Dover,
Delaware
(USA) USA USD 156,600,000 Eni SpA
Eni International BV 63.86
36.14 100.00 F.C.
Eni Petroleum US Llc Dover,
Delaware
(USA) USA USD 1,000 Eni BB Petroleum Inc 100.00 100.00 F.C.
Eni Portugal BV Amsterdam
(Netherlands) Portugal EUR 20,000 Eni International BV 100.00 Eq.
Eni RAK BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Rapak Ltd London
(United
Kingdom) Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni RD Congo SA Kinshasa
(Democratic
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 100.00 100.00 F.C.
Eni Sharjah BV Amsterdam
(Netherlands) United
Arab
Emirates EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni South Africa BV Amsterdam
(Netherlands) Republic of
South Africa EUR 20,000 Eni International BV 100.00 100.00 F.C.

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

1

Eni International BV

100.00

Eq.

Eni Bukat Ltd

London
(United
Kingdom)

Indonesia

GBP

1

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

1

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

1

Eni Indonesia Ltd

100.00

F.C.

Eni East Sepinggan Ltd

London
(United
Kingdom)

Indonesia

GBP

1

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

2

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 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 100.00 100.00 F.C.
Eni Tunisia BV Amsterdam
(Netherlands) Tunisia EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Turkmenistan Ltd Hamilton
(Bermuda) Turkmenistan USD 20,000 Burren En.(Berm)Ltd 100.00 100.00 F.C.
Eni UHL Ltd London
(United
Kingdom) United
Kingdom GBP 1 Eni ULT Ltd 100.00 100.00 F.C.
Eni UK Holding Plc London
(United
Kingdom) United
Kingdom GBP 424,050,000 Eni Lasmo Plc
Eni UK Ltd
99.99
(..)
100.00 F.C.
Eni UK Ltd London
(United
Kingdom) United
Kingdom GBP 250,000,000 Eni International BV 100.00 100.00 F.C.
Eni UKCS Ltd London
(United
Kingdom) United
Kingdom GBP 100 Eni UK Ltd 100.00 100.00 F.C.
Eni Ukraine Holdings BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni Ukraine Llc Kiev
(Ukraine) Ukraine UAH 42,004,757.64 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 100.00 100.00 F.C.
Eni ULX Ltd London
(United
Kingdom) United
Kingdom GBP 200,010,000 Eni ULT Ltd 100.00 100.00 F.C.
Eni US Operating Co Inc Dover,
Delaware
(USA) USA USD 1,000 Eni Petroleum Co Inc 100.00 100.00 F.C.
Eni USA Gas Marketing Llc Dover,
Delaware
(USA) USA USD 10,000 Eni Marketing Inc 100.00 100.00 F.C.
Eni USA Inc Dover,
Delaware
(USA) USA USD 1,000 Eni Oil & Gas Inc 100.00 100.00 F.C.
Eni Venezuela BV Amsterdam
(Netherlands) Venezuela EUR 20,000 Eni Venezuela
E&P Holding 100.00 100.00 F.C.
Eni Venezuela E&P Holding SA Bruxelles
(Belgium) Belgium USD 254,443,200 Eni International BV
Eni Oil Holdings BV
99.99
(..)
100.00 F.C.
Eni Ventures Plc
(in liquidation)
London
(United
Kingdom) United
Kingdom GBP 278,050,000 Eni International BV
Eni Oil Holdings BV
99.99
(..)
Co.
Eni Vietnam BV Amsterdam
(Netherlands) Vietnam EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni West Ganal Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni West Timor Ltd London
(United
Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 F.C.
Eni Yemen Ltd London
(United
Kingdom) United
Kingdom GBP 1,000 Burren Energy Plc 100.00 Eq.
EniProgetti Egypt Ltd Cairo
(Egypt) Egypt EGP 50,000 EniProgetti SpA
Eni SpA 99.00
1.00 Eq.
Eurl Eni Algérie Algiers
(Algeria) Algeria DZD 1,000,000 Eni Algeria Ltd Sàrl 100.00 Eq.

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

2

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

1

Eni UK Ltd

100.00

Eq.

Eni LNS Ltd

London
(United
Kingdom)

United Kingdom

GBP

1

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(*)

First Calgary Petroleums LP Wilmington
(USA) Algeria USD 1 Eni Canada Hold. Ltd
FCP Partner Co ULC 99.99
0.01 100.00 F.C.
First Calgary Petroleums Partner Co ULC Calgary
(Canada) Canada CAD 10 Eni Canada Hold. Ltd 100.00 100.00 F.C.
Ieoc Exploration BV Amsterdam
(Netherlands) Egypt EUR 20,000 Eni International BV 100.00 100.00 F.C.
Ieoc Production BV Amsterdam
(Netherlands) Egypt EUR 20,000 Eni International BV 100.00 100.00 F.C.
Lasmo Sanga Sanga Ltd Hamilton
(Bermuda) Indonesia USD 12,000 Eni Lasmo Plc 100.00 100.00 F.C.
Liverpool Bay Ltd London
(United Kingdom) United Kingdom USD 1 Eni ULX Ltd 100.00 Eq.
Mizamtec Operating Company S. de RL de CV Mexico City
(Mexico) Mexico MXN 3,000 Eni US Op. Co Inc
Eni Petroleum Co Inc 99.90
0.10 Eq.
Nigerian Agip CPFA Ltd Lagos
(Nigeria) Nigeria NGN 1,262,500 NAOC Ltd
Agip En Nat Res.Ltd
Nigerian Agip E. Ltd 98.02
0.99
0.99 Co.
Nigerian Agip Exploration
Ltd Abuja
(Nigeria) Nigeria NGN 5,000,000 Eni International BV
Eni Oil Holdings BV 99.99
0.01 100.00 F.C.
Nigerian Agip Oil Co Ltd Abuja
(Nigeria) Nigeria NGN 1,800,000 Eni International BV
Eni Oil Holdings BV 99.89
0.11 100.00 F.C.
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.

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

1

Eni ULT Ltd

100.00

F.C.

Eni MOG Ltd
(in liquidation)

London
(United
Kingdom)

United
Kingdom

GBP

0

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

1

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

1

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

2

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

~~Gas & Power~~

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 100.00 100.00 F.C.
Eni Gas Transport Services Srl San Donato
Milanese (MI) Italy EUR 120,000 Eni SpA 100.00 Co.
Eni Trading & Shipping SpA Rome Italy EUR 60,036,650 Eni SpA 100.00 100.00 F.C.
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 100.00 100.00 F.C.
LNG Shipping SpA San Donato Milanese (MI) Italy EUR 240,900,000 Eni SpA 100.00 100.00 F.C.
SEA SpA L’Aquila (AQ) Italy EUR 100,000
Eni gas e luce SpA
Third parties

60.00
40.00
60.00 F.C.
Trans Tunisian Pipeline Co SpA San Donato Milanese (MI) Tunisia EUR 1,098,000 Eni SpA 100.00 100.00 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 G&P Trading BV
Amsterdam
(Netherlands)
Turkey EUR 70,000 Eni International BV 100.00 100.00 F.C.
Eni Gas & Power France SA
Levallois Perret
(France)
France EUR 29,937,600
Eni gas e luce SpA
Third parties

99.87
0.13
99.87 F.C.
Eni Trading & Shipping Inc
Dover, Delaware
(USA)
USA USD 36,000,000 ETS SpA 100.00 100.00 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.
Gas Supply Company Thessaloniki –
Thessalia SA
Thessaloniki
(Greece)
Greece EUR 13,761,788 Eni gas e luce SpA 100.00 100.00 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.

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

1

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

0

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

1

Eni Indonesia Ltd

100.00

F.C.

Eni West Timor Ltd

London
(United
Kingdom)

Indonesia

GBP

1

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

1

Eni Canada Hold. Ltd
FCP Partner Co ULC

99.99
0.01

100.00

F.C.

First Calgary Petroleums Partner Co ULC

Calgary
(Canada)

Canada

CAD

10

Eni Canada Hold. Ltd

100.00

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

~~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 100.00 100.00 F.C.
Eni Fuel SpA Rome Italy EUR 58,944,310 Eni SpA 100.00 100.00 F.C.
Petroven Srl Genova Italy EUR 918,520 Ecofuel SpA 100.00 100.00 F.C.
Raffineria di Gela SpA Gela (CL) Italy EUR 15,000,000 Eni SpA 100.00 100.00 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 100.00 100.00 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 100.00 100.00 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 100.00 100.00 F.C.
Eni Iberia SLU
Alcobendas
(Spain)
Spain EUR 17,299,100 Eni International BV 100.00 100.00 F.C.
Eni Lubricants Trading (Shanghai)
Co Ltd
Shanghai
(China)
China EUR 5,000,000 Eni International BV 100.00 100.00 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 100.00 100.00 F.C.
Eni Schmiertechnik GmbH
Wurzburg
(Germany)
Germany EUR 2,000,000 Eni Deutsch.GmbH 100.00 100.00 F.C.
Eni Suisse SA
Lausanne
(Switzerland)
Switzerland CHF 102,500,000 Eni International BV 100.00 100.00 F.C.
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.

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

1

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

~~Chemical~~Global Gas & LNG Portfolio

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 100.00 100.00 F.C.
Outside Italy
Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság
Budapest
(Hungary)
Hungary HUF 8,092,160,000
Versalis SpA
Versalis Deutsc.GmbH
Versalis Int.SA

96.34
1.83
1.83
100.00 F.C.
Versalis Americas Inc
Dover,
Delaware
(USA)
USA USD 100,000 Versalis
International SA 100.00 100.00 F.C.
Versalis Congo Sarlu
Pointe-Noire
(Republic of
the Congo)
Republic of
the Congo XAF 1,000,000 Versalis
International SA 100.00 100.00 F.C.
Versalis Deutschland GmbH
Eschborn
(Germany)
Germany EUR 100,000 Versalis SpA 100.00 100.00 F.C.
Versalis France SAS
Mardyck
(France)
France EUR 126,115,582.90 Versalis SpA 100.00 100.00 F.C.
Versalis International 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 Eq.
Versalis México S. de R.L. de CV
Mexico City
(Mexico)
Mexico MXN 1,000
Versalis Int. SA
Versalis SpA

99.00
1.00
Eq.
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 100.00 100.00 F.C.
Versalis Singapore Pte Ltd
Singapore
(Singapore)
Singapore SGD 80,000 Versalis SpA 100.00 100.00 F.C.
Versalis UK Ltd
London
(United Kingdom)
United
Kingdom GBP 4,004,042 Versalis SpA 100.00 100.00 F.C.

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

~~Corporate~~Refining & Marketing and ~~Other activities~~Chemical

~~Corporate and financial companies~~Refining & Marketing

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 100.00 100.00 F.C.
D-Service Media Srl
(in liquidation)
Milan Italy EUR 75,000 D-Share SpA 100.00
D-Share SpA Milan Italy EUR 121,719.25
Agi SpA
Third parties

55.21
44.79
Co.
Eni Corporate University SpA San Donato
Milanese (MI) Italy EUR 3,360,000 Eni SpA 100.00 100.00 F.C.
EniServizi SpA San Donato
Milanese (MI) Italy EUR 13,427,419.08 Eni SpA 100.00 100.00 F.C.
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 100.00 100.00 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
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,
Delaware
(USA)
USA USD 15,000,000 Eni Petroleum Co Inc 100.00 100.00 F.C.
Eni Insurance DAC
Dublin
(Ireland)
Ireland EUR 500,000,000 Eni SpA 100.00 100.00 F.C.
Eni International BV
Amsterdam
(Netherlands)
Netherlands EUR 641,683,425 Eni SpA 100.00 100.00 F.C.
Eni International Resources Ltd
London
(United
Kingdom)
United Kingdom GBP 50,000
Eni SpA
Eni UK Ltd

99.99
(..)
100.00 F.C.
Eni Next Llc
Houston
(USA)
USA USD 100 Eni Petroleum Co Inc 100.00 100.00 F.C.

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

~~(a)~~

~~Shares without nominal value.~~

F-130

TABLE OF CONTENTS

~~Other activities~~Chemical

Company name Registered
office Country
of operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

In Italy
Anic Partecipazioni SpA
(in liquidation)
Gela (CL) Italy EUR 23,519,847.16 Eni Rewind SpA
Third parties 99.97
0.03 Eq.
Eni Energia Srl San Donato
Milanese (MI) Italy EUR 10,000 Eni SpA 100.00 Co.
Eni Energy Activities Srl San Donato
Milanese (MI) Italy EUR 50,000 Eni SpA 100.00 Co.
Eni New Energy SpA San Donato
Milanese (MI) Italy EUR 9,296,000 Eni SpA 100.00 100.00 F.C.
Eni Rewind SpA
(former Syndial Servizi Ambientali SpA) San Donato
Milanese (MI) Italy EUR 425,343,731.50 Eni SpA
Third parties 99.99
(..) 100.00 F.C.
Industria Siciliana Acido Fosforico-ISAF-SpA
(in liquidation)
Gela (CL) Italy EUR 1,300,000 Eni Rewind SpA
Third parties 52.00
48.00 Eq.
Ing. Luigi Conti
Vecchi SpA Assemini (CA) Italy EUR 5,518,620.64 Eni Rewind SpA 100.00 100.00 F.C.
Outside Italy
Arm Wind Llp Nur-Sultan
(Kazakhstan) Kazakhstan KZT 7,963,200,000 Windirect BV 100.00 100.00 F.C.
Eni Energy Solutions BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 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, Delaware
(USA) USA USD 100 Eni Petroleum Co Inc 100.00 Eq.
Eni Rewind
International BV Amsterdam
(Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 Eq.
Oleodotto del Reno SA Coira
(Switzerland) Switzerland CHF 1,550,000 Eni Rewind SpA 100.00 Eq.
Windirect BV Amsterdam
(Netherlands) Netherlands EUR 10,000 Eni International BV 100.00 100.00 F.C.

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

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

~~Joint arrangements and associates~~Eni gas e luce, Power & Renewables

~~Exploration & Production~~Eni gas e luce

~~In Italy~~

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method (*)

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 172.1 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 Co.
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) Reading, Berkshire
(United Kingdom) United Kingdom GBP 100 Agip Karachag.BV
Third parties 38.00
62.00 Eq.
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.

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

~~(†)~~

~~Jointly controlled entity.~~

(a)

Shares without nominal value.

~~F-132~~F-134

TABLE OF CONTENTS

~~Company name~~

~~Registered~~
~~office~~

~~Country of~~
~~operation~~

~~Currency~~

~~Share~~
~~Capital~~

~~Shareholders~~

%
~~Ownership~~

~~% Equity~~
~~ratio~~

~~Consolidation~~
~~or valutation~~
~~method(*)~~

~~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.~~

~~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~~

~~Co.~~

~~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~~

~~Maputo~~
~~(Mozambique)~~

~~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.~~

~~Tecninco Engineering~~
~~Contractors Llp~~ ~~(†)~~

~~Aksai~~
~~(Kazakhstan)~~

~~Kazakhstan~~

~~KZT~~

~~29,478,455~~

~~EniProgetti SpA~~
~~Third parties~~

~~49.00~~
~~51.00~~

~~Eq.~~

~~Thekah Petroleum Co~~
~~(in liquidation)~~

~~Cairo~~
~~(Egypt)~~

~~Egypt~~

~~EGP~~

~~20,000~~

~~Ieoc Exploration BV~~
~~Third parties~~

~~25.00~~
~~75.00~~

~~Co.~~

~~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~~

~~69.60~~
~~30.40~~

~~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~~

~~Co.~~

Other activities

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Anic Partecipazioni SpA
(in liquidation)

Gela (CL)

Italy

EUR

23,519,847.16

Eni Rewind SpA
Third parties

99.97
0.03

Eq.

Eni Rewind SpA

San Donato
Milanese (MI)

Italy

EUR

355,145,040.30

Eni SpA
Third parties

99.99
(..)

100.00

F.C.

Industria Siciliana Acido Fosforico - ISAF -SpA
(in liquidation)

Gela (CL)

Italy

EUR

1,300,000

Eni Rewind SpA
Third parties

52.00
48.00

Eq.

Ing. Luigi Conti Vecchi SpA

Assemini (CA)

Italy

EUR

5,518,620.64

Eni Rewind SpA

100.00

F.C.

Outside Italy

Eni Rewind International BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Oleodotto del Reno SA

Coira
(Switzerland)

Switzerland

CHF

1,550,000

Eni Rewind SpA

100.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-135

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-133~~F-136

TABLE OF CONTENTS

~~Gas & Power~~

~~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.
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.
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.
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.
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 Eni International BV
Transmed.Pip.Co Ltd
Third parties 5.00
90.00
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.

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)

~~Equity ratio equal to the Eni’s working interest.~~Shares without nominal value.

~~F-134~~F-137

TABLE OF CONTENTS

~~Refining~~Global Gas & ~~Marketing and Chemical~~

~~Refining & Marketing~~LNG Portfolio

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 Co.
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(†)
San Donato
Milanese (MI) Italy EUR 3,085,000 Eni SpA
Third parties 70.00
30.00 70.00 J.O.
Termica Milazzo Srl(†)
Milazzo (ME) Italy EUR 100,000 Raff. Milazzo ScpA 100.00 50.00 J.O.

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-135~~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

F-139

TABLE OF CONTENTS

Outside Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

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.

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.

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.

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.

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.

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.

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

1

Eni France Sàrl
Third parties

25.00
75.00

Co.

Tremblay en France
(France)

France

EUR

1

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.

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.

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.

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.

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 Betriebs
gesellschaft GmbH(†)

Salzburg
(Austria)

Austria

EUR

43,603.70

Eni Market.A.GmbH
Third parties

50.00
50.00

Eq.

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.

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-136~~F-140

TABLE OF CONTENTS

Chemical

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

~~% Equity~~
~~ratio~~

% 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~~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~~57.98

Eq.

Matrìca SpA(†)

Porto Torres (SS)

Italy

EUR

37,500,000

Versalis SpA
Third parties

50.00
~~50.00~~

~~Eq.~~

~~Novamont SpA~~

~~Novara~~

~~Italy~~

~~EUR~~

~~13,333,500~~

~~Versalis SpA~~
~~Third parties~~

~~25.00~~
~~75.00~~50.00

Eq.

Priolo Servizi ScpA

Melilli (SR)

Italy

EUR

28,100,000

Versalis SpA
Eni Rewind SpA
Third parties

~~33.11~~

35.15
~~4.61~~5.04
~~62.28~~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~~25.65

Eq.

Servizi Porto Marghera Scarl

~~Porto~~Venezia Marghera (VE)

Italy

EUR

8,695,718

Versalis SpA
Eni Rewind SpA
Third parties

48.44
38.39
~~13.17~~13.17

Eq.

Outside Italy

Lotte Versalis Elastomers Co
Ltd(†(†)

Yeosu
(South Korea)

South Korea

KRW

~~401,800,000,000~~501,800,000,000

Versalis SpA
Third parties

50.00
~~50.00~~

~~Eq.~~

~~Versalis Zeal~~
~~Ltd~~ ~~(†)~~50.00

~~Takoradi~~
~~(Ghana)~~

~~Ghana~~

~~GHS~~

~~5,650,000~~

~~Versalis Intern. SA~~
~~Third parties~~

~~80.00~~
~~20.00~~

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~~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.

~~F-137~~F-141

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

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~~

% Equity
ratio

Consolidation
or valutation
method(*)

~~Outside~~

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.

~~Commonwealth Fusion~~
~~Systems Llc(a)~~Saipem SpA(#) (†)

~~Wilmington~~San Donato
~~(USA)~~Milanese (MI)

~~USA~~Italy

~~USD~~EUR

~~115,000,519~~2,191,384,693

Eni ~~Next Llc~~SpA
Saipem SpA
Third parties

30.54(a)
1.73
67.73

Eq.

~~Form Energy Inc~~Outside Italy~~(b)~~

~~Sommerville~~

Commonwealth Fusion Systems Llc

Wilmington
(USA)

USA

USD

~~50,889,548.24~~215,000,514.83

Eni Next Llc
Third parties

Eq.

~~Other activities~~

~~In Italy~~

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

~~Ottana Sviluppo ScpA~~
~~(in bankruptcy)~~

~~Nuoro~~

~~Italy~~

~~EUR~~

~~516,000~~

~~Eni Rewind SpA~~
~~Third parties~~

~~30.00~~

~~70.00~~

~~Eq.~~

Progetto Nuraghe Scarl

Porto Torres
(SS)

Italy

EUR

10,000

Eni Rewind SpA
Third parties

~~48.55~~

~~51.45~~

~~Eq.~~

~~Saipem SpA(#) (†)~~

~~San Donato Milanese (MI)~~

~~Italy~~

~~EUR~~

~~2,191,384,693~~

~~Eni SpA~~
~~Saipem SpA~~
~~Third parties~~

~~30.54~~(c)48.55
~~1.46~~
~~68.00~~

~~Eq.~~

~~Outside Italy~~

~~Ayla Energy Ltd(†)~~51.45

~~London~~
~~(United Kingdom)~~

~~United Kingdom~~

~~USD~~

~~1,000~~

~~Eni En. Solutions BV~~
~~Third parties~~

~~50.00~~

~~50.00~~

~~Eq.~~

~~Grid Edge (Private) Ltd(†)~~

~~Saddar Town - Karachi~~
~~(Pakistan)~~

~~Pakistan~~

~~PKR~~

~~1,200,000~~

~~Eni International BV~~
~~Third parties~~

~~40.00~~

~~60.00~~

~~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~~

~~20,000~~

~~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

(#)

Company with shares quoted in the regulated market of Italy or of other EU countries

(†)

Jointly controlled entity.

~~(a)~~

~~The ownership cannot be determined. The capital subscribed by Eni Next Llc amounts to $50 million.~~

~~(b)~~

~~The ownership cannot be determined. The capital subscribed by Eni Next Llc amounts to $15 million.~~

~~(c)~~(a)

Controlling interest:

Eni SpA
Third parties

~~30.99~~31.08
~~69.01~~68.92

~~F-138~~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

~~135,000~~136,000

Eni SpA
Third parties

20.00
~~80.00~~80.00

F.V.

~~Outside Italy~~

Outside Italy

Administradora del Golfo de Paria Este SA

Caracas
(Venezuela)

Venezuela

VES

0.001

Eni Venezuela BV
Third parties

19.50
~~80.50~~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~~79.52

F.V.

Darwin LNG Pty Ltd

West Perth
(Australia)

Australia

AUD

~~367,278,503.01~~187,569,921.42

Eni G&P LNG Aus. BV
Third parties

10.99

~~89.01~~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~~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~~89.60

F.V.

North Caspian Operating Co
Company NV

~~Amsterdam~~The Hague
(Netherlands)

Kazakhstan

EUR

128,520

Agip Caspian Sea BV
Third parties

16.81

~~83.19~~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~~86.40

F.V.

Petrolera Güiria SA

Caracas
(Venezuela)

Venezuela

VES

10

Eni Venezuela BV
Third parties

19.50
~~80.50~~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

~~13.60~~

10.57

~~86.40~~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
~~87.50~~(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-139~~F-144

TABLE OF CONTENTS

~~Gas~~Refining & ~~Power~~Marketing and Chemical

~~Outside~~Refining & Marketing

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

Consolidation
or valutation
method(*)

~~Norsea Gas GmbH~~Società Italiana Oleodotti di Gaeta SpA

~~Emden~~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

~~1,533,875.64~~89,199

Eni ~~International BV~~Deutsch.GmbH
Third parties

~~13.04~~

12.50
~~86.96~~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

Corporate e and other activities attività

Other activities

In Italy

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

Consolidation or valutation method(*)

Ottana Sviluppo ScpA
(in bankruptcy)

Nuoro

Italy

EUR

516,000

Eni Rewind SpA
Third parties

30.00
70.00

F.V.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

~~F-140~~

~~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(a)~~

~~Rome~~

~~Italy~~

~~ITL~~

~~360,000,000~~

~~Eni SpA~~
~~Third parties~~

~~72.48~~
~~27.52~~

~~F.V.~~

~~Outside Italy~~

~~Company name~~

~~Registered~~
~~office~~

~~Country of~~
~~operation~~

~~Currency~~

~~Share~~
~~Capital~~

~~Shareholders~~

~~% Ownership~~

~~Consolidation~~
~~or valutation~~
~~method(*)~~

~~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(b)

~~Eni SpA~~
~~Third parties~~

~~12.50~~
~~87.50~~

~~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.~~

~~(*)~~

~~F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value~~

~~(a)~~

Company under extraordinary administration procedure pursuant to law no. 95 of april 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the authorization by the Ministry of Economic Development.

~~(b)~~

~~Shares without nominal value.~~

~~F-141~~F-146

TABLE OF CONTENTS

Information on Eni’s consolidated subsidiaries with significant non-controlling interest

In ~~2019~~2020 and ~~2018,~~2019, Eni did not own any consolidated subsidiaries with a significant non-controlling interest.

~~The total shareholders’ equity~~Equity pertaining to minority interests as of December 31, ~~2019,~~2020, amounted to ~~€61~~€78 million (€5761 million December 31, ~~2018)~~2019).

Changes in the ownership interest without loss of control

In ~~2019, Eni acquired a 10% stake of Windirect BV. In 2018,~~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, ~~2019~~2020

Company name

Registered office

Country of
operation

Business segment

% ownership
interest

Eni’s % of
the investment

Registered office

Country of
operation

Business segment

% ownership
interest

Eni’s % of
the investment

Joint venture

Vår Energi AS

Forus
(Norway)

Norway

Exploration & Production

69.60

Forus
(Norway)

Norway

Exploration & Production

69.85

Saipem SpA

San Donato Milanese
(MI) (Italy)

Italy

Other Activities

30.54

30.99

San Donato Milanese
(MI)
(Italy)

Italy

Corporate and financial companies

30.54

31.08

Unión Fenosa Gas SA

Madrid
(Spain)

Spain

Gas & Power

50.00

Madrid
(Spain)

Spain

Global Gas & LNG Portfolio

50.00

Cardón IV SA

Caracas
(Venezuela)

Venezuela

Exploration & Production

50.00

Caracas
(Venezuela)

Venezuela

Exploration & Production

50.00

Gas Distribution Company of Thessaloniki - Thessaly SA

Ampelokipi-Menemeni
(Greece)

Greece

Gas & Power

49.00

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

San Donato Milanese
(MI) (Italy)

Mozambique

Exploration & Production

35.71

Raffineria di Milazzo ScpA

Milazzo
(ME) (Italy)

Italy

Refining & Marketing

50.00

GreenStream BV

Amsterdam
(Netherlands)

Libya

Gas & Power

50.00

Amsterdam
(Netherlands)

Libya

Global Gas & LNG Portfolio

50.00

Blue Stream Pipeline Co BV

Amsterdam
(Netherlands)

Russia

Gas & Power

74.62

Associates

Abu Dhabi Oil Refining Co (Takreer)

Abu Dhabi
(United Arab Emirates)

United Arab
Emirates

Refining & Marketing

20.00

Abu Dhabi
(United Arab Emirates)

United Arab
Emirates

Refining & Marketing

20.00

Angola LNG Ltd

Hamilton
(Bermuda)

Angola

Exploration & Production

13.60

Hamilton
(Bermuda)

Angola

Exploration & Production

13.60

Coral FLNG SA

Maputo
(Mozambique)

Mozambique

Exploration & Production

25.00

Maputo
(Mozambique)

Mozambique

Exploration & Production

25.00

~~F-142~~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:

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 329 456 (19) 56 28 (54)
Finance income (expense) (1) (210) (37) (133) (1) (14)
Income (expense) from investments (18) 6
Profit before income taxes 328 228 (50) (77) 27 (68)
Income taxes (258) (130) 8 (103) (7) (12)
Net profit 70 98 (42) (180) 20 (80)
Other comprehensive income 40 66 11 5
Total other comprehensive income 110 164 (31) (175) 20 (80)
Net profit attributable to Eni 49 4 (14) (90) 10 (40)
Dividends received from the joint venture 1,057 10 6

2018
(€ million) Vår Energi
AS Saipem
SpA Unión
Fenosa Gas
SA Gas
Distribution
Company of
Thessaloniki
-Thessaly SA Cardón IV SA Lotte
Versalis
Elastomers
Co Ltd PetroJunín
SA Other
joint
ventures
Current assets 1,366 6,211 664 32 191 56 368 130
- of which cash and cash equivalent 883 1,674 107 13 40 8 38
Non-current assets 11,407 5,466 832 302 2,433 502 253 334
Total assets 12,773 11,677 1,496 334 2,624 558 621 464
Current liabilities 608 4,430 260 52 232 111 470 307
- current financial liabilities 305 22 78 165
Non-current liabilities 7,139 3,211 581 2 2,196 297 34 126
- non-current financial liabilities 366 2,646 510 1,410 289 14
Total liabilities 7,747 7,641 841 54 2,428 408 504 433
Net equity 5,026 4,036 655 280 196 150 117 31
Eni’s % of the investment 69.60 30.99 50.00 49.00 50.00 50.00 40.00
Book value of the investment 3,498 1,228 335 137 98 75 47
(2)

Revenues and other income 8,530 1,521 53 610 22 112 731
Operating expense (7,682) (1,461) (16) (372) (58) (100) (697)
Depreciation, amortization and impairments (811) (70) (12) (137) (30) (394) (62)
Operating profit 37 (10) 25 101 (66) (382) (28)
Finance income (expense) (165) (31) (208) (12) 31 (5)
Income (expense) from investments (88) 9
Profit before income taxes (216) (32) 25 (107) (78) (351) (33)
Income taxes (194) (1) (8) (35) (19) (10)
Net profit (410) (33) 17 (142) (78) (370) (43)
Other comprehensive income (46) 15 6 11 (4)
Total other comprehensive income (456) (18) 17 (136) (78) (359) (47)
Net profit attributable to Eni (146) (23) 8 (71) (39) (148) (21)
Dividends received from the joint venture 8 11


	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

~~F-143~~F-148

TABLE OF CONTENTS

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:

2019
(€ million) Abu Dhabi
Oil Refining Co
(TAKREER) Angola LNG
Ltd Coral
FLNG
SA Other
associates
Current assets 4,659 890 241 838
- of which cash and cash equivalent 42 653 240 91
Non-current assets 18,868 9,952 4,119 3,259
Total assets 23,527 10,842 4,360 4,097
Current liabilities 8,470 185 230 585
- current financial liabilities 3,694 63
Non-current liabilities 912 2,135 3,722 2,677
- non-current financial liabilities 479 1,943 3,722 2,515
Total liabilities 9,382 2,320 3,952 3,262
Net equity 14,145 8,522 408 835
Eni’s % of the investment 20.00 13.60 25.00
Book value of the investment 2,829 1,159 102 264
Revenues and other income 399 1,552 818
Operating expense (357) (549) (763)
Depreciation, amortization and impairments (335) (509) (28)
Operating profit (293) 494 27
Finance income (expense) (46) (151) (12) (2)
Income (expense) from investments 282 35
Profit before income taxes (57) 343 (12) 60
Income taxes 11 5 (10)
Net profit (46) 343 (7) 50
Other comprehensive income (59) 162 8 5
Total other comprehensive income (105) 505 1 55
Net profit attributable to Eni (9) 47 (2) 22
Dividends received from the associate 46 15


	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

~~F-144~~F-149

TABLE OF CONTENTS

2018
(€ million) Angola LNG
Ltd Coral
FLNG
SA Other
associates
Current assets 1,027 109 926
- of which cash and cash equivalent 698 109 178
Non-current assets 9,079 2,434 2,296
Total assets 10,106 2,543 3,222
Current liabilities 472 117 785
- current financial liabilities 134
Non-current liabilities 1,500 2,018 1,755
- non-current financial liabilities 1,328 2,016 1,473
Total liabilities 1,972 2,135 2,540
Net equity 8,134 408 682
Eni’s % of the investment 13.60 25.00
Book value of the investment 1,106 102 241
Revenues and other income 1,919 1,053
Operating expense (872) (1) (887)
Depreciation, amortization and impairments 1,647 (58)
Operating profit 2,694 (1) 108
Finance income (expense) (97) (11) (1)
Income (expense) from investments 16
Profit before income taxes 2,597 (12) 123
Income taxes (26)
Net profit 2,597 (12) 97
Other comprehensive income 337 16 17
Total other comprehensive income 2,934 4 114
Net profit attributable to Eni 353 (3) 25
Dividends received from the associate 25


	2019
(€ million)	Abu Dhabi Oil Refining Co (TAKREER)		Angola LNG Ltd		Coral FLNG SA		Other associates
Current assets		4,659		890		241		838
- of which cash and cash equivalent		42		653		240		91
Non-current assets		18,868		9,952		4,119		3,259
Total assets		23,527		10,842		4,360		4,097
Current liabilities		8,470		185		230		585
- current financial liabilities		3,694						63
Non-current liabilities		912		2,135		3,722		2,677
- non-current financial liabilities		479		1,943		3,722		2,515
Total liabilities		9,382		2,320		3,952		3,262
Net equity		14,145		8,522		408		835
Eni’s % of the investment		20.00		13.60		25.00
Book value of the investment		2,829		1,159		102		264
Revenues and other income		399		1,552				818
Operating expense		(357)		(549)				(763)
Depreciation, amortization and impairments		(335)		(509)				(28)
Operating profit (loss)		(293)		494				27
Finance income (expense)		(46)		(151)		(12)		(2)
Income (expense) from investments		282						35
Profit (loss) before income taxes		(57)		343		(12)		60
Income taxes		11				5		(10)
Net profit (loss)		(46)		343		(7)		50
Other comprehensive income (loss)		(59)		162		8		5
Total other comprehensive income (loss)		(105)		505		1		55
Net profit (loss) attributable to Eni		(9)		47		(2)		22
Dividends received from the associate		46						15

~~F-145~~F-150

TABLE OF CONTENTS

38 Significant non-recurring events and operations

In 2020, in 2019 inand 2018, ~~and 2017,~~ Eni did not report any non-recurring events and operations.

39 Positions or transactions deriving from atypical and/or unusual operations

In 2020, in 2019 ~~2018~~ and ~~2017~~2018, no transactions deriving from atypical and/or unusual operations were reported.

40 Subsequent events

~~Impact of COVID-19 and current trends~~No significant events were reported after December 31, 2020, apart from what is already included in the ~~oil market~~

~~The outbreak of a contagious disease known as COVID-19 which has spread rapidly~~notes to many countries in the world at the beginning of 2020 and is currently ongoing has triggered a sharp sell-off in energy commodities markets due to a sudden drop in worldwide consumption of oil, gas and other energy products as a result of measures taken worldwide to contain the spread of the disease. In early March 2020, members of the OPEC+ failed to reach a new deal for additional oil production cuts desired by some participants to counteract the decrease in demand from COVID-19 effects. These developments triggered a collapse in crude oil prices. The price of the Brent crude benchmark has fallen by more than 50% from 65$/BBL early in January 2020 to current values; however the average Brent price for the first quarter 2020 of approximately 51$/BBL has fallen by a considerably lower amount over the corresponding period a year ago (down by approximately 20%). Also, the price of natural gas at the Italian spot market “PSV”, which is the main benchmark for sales volumes of equity gas production has fallen in this period, with the average price for the first quarter 2020 at approximately 3.7$/mmBTU, down by approximately 50% over the year-ago quarter.

Future trends in crude oil and natural gas prices will greatly depend on how the current COVID-19 crisis unfolds and on how long it lasts. Under the worst of the assumptions, the spread of the disease could trigger a global recession which could materially hit demand for energy products and prices of energy commodities. This scenario could be further complicated in case the members of the OPEC+ continue to cease supporting crude oil prices. 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.

We retain some levers of financial flexibility in case of a significant contraction in cash flow from operations. The Group has established a liquidity reserve consisting of very liquid sovereign bonds and corporate securities which amounted to €6.8 billion at the balance sheet date, which together with cash on hands of approximately €6 billion will cushion the impact of a decline in liquidity. Furthermore, we have as of December 31, 2019, undrawn uncommitted borrowing facilities amounting to €13,299 million and undrawn long-term committed borrowing facilities of €4,667 million. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. The main financial commitments of 2020 include long-term debt maturities of approximately €3.2 billion and short-term debt of €2.45 billion, while our take-or-pay obligations under long-term gas contracts and other similar obligations amount to an estimated €8 billion at our budget scenario.

The effects of the recent trends in the oil market on the Group’s results of operations, liquidity and assets are currently under evaluation by management. This assessment implies the oil price scenario update and the management’s actions to counteract the changed environment, the effects of which, currently not yet determinable, will be accounted for in future reporting periods.these Financial Statements.

~~F-146~~F-151

TABLE OF CONTENTS

Supplemental oil and gas information (unaudited)

The following information ~~pursuant to~~prepared in accordance with “International Financial Reporting Standards” ~~(IFRS)~~(IFRS) is presented ~~in accordance with~~based on the disclosure rules of the FASB Extractive Activities — Oil & Gas (Topic 932). Amounts related to minority interests are ~~not significant.~~immaterial.

Capitalized costs

Capitalized costs represent the total expenditures for proved and unproved mineral ~~interests~~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) 2019	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
(€ 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		17,643		6,747		15,512		20,691		43,272		12,118		11,434		15,912		1,360		144,689		18,456		6,465		14,596		19,081		39,848		11,278		10,662		14,567		1,359		136,312
Unproved property		18		323		502		34		2,361		11		1,592		979		194		6,014		20		311		454		33		2,163		10		1,411		896		179		5,477
Support equipment and facilities		384		21		1,549		225		1,328		116		36		23		12		3,694		300		20		1,424		216		1,226		109		34		20		11		3,360
Incomplete wells and other		635		103		1,362		359		2,541		1,165		1,006		457		43		7,671		671		147		1,094		193		2,551		1,064		1,469		458		39		7,686
Gross Capitalized Costs		18,680		7,194		18,925		21,309		49,502		13,410		14,068		17,371		1,609		162,068		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		(14,604)		(5,778)		(12,802)		(12,879)		(33,237)		(2,652)		(9,100)		(13,465)		(754)		(105,271)		(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)		4,076		1,416		6,123		8,430		16,265		10,758		4,968		3,906		855		56,797		3,882		1,346		4,775		7,362		13,540		9,622		4,573		3,329		783		49,212
Equity-accounted entities
Proved property				11,223		71				1,511				2		1,987				14,794				11,466		68				1,384						1,833				14,751
Unproved property				2,260										11						2,271				2,131										11						2,142
Support equipment and facilities				19		8										7				34				23		8										6				37
Incomplete wells and other				945		7				15				19		229				1,215				1,566		9				17						209				1,801
Gross Capitalized Costs				14,447		86				1,526				32		2,223				18,314				15,186		85				1,401				11		2,048				18,731
Accumulated depreciation, depletion and amortization				(5,287)		(61)				(323)				(20)		(1,124)				(6,815)				(6,196)		(59)				(343)						(1,076)				(7,674)
Net Capitalized Costs equity-accounted entities ~~(c)~~(a)				9,160		25				1,203				12		1,099				11,499				8,990		26				1,058				11		972				11,057
2018
2019
Consolidated subsidiaries
Proved property		16,569		6,236		14,140		17,474		40,607		11,240		12,711		15,347		1,967		136,291		17,643		6,747		15,512		20,691		43,272		12,118		11,434		15,912		1,360		144,689
Unproved property		18		332		456		56		2,311		3		1,530		861		193		5,760		18		323		502		34		2,361		11		1,592		979		194		6,014
Support equipment and facilities		369		21		1,516		208		1,281		108		38		52		12		3,605		384		21		1,549		225		1,328		116		36		23		12		3,694
Incomplete wells and other		653		103		1,554		1,504		2,307		1,382		562		595		127		8,787		635		103		1,362		359		2,541		1,165		1,006		457		43		7,671
Gross Capitalized Costs		17,609		6,692		17,666		19,242		46,506		12,733		14,841		16,855		2,299		154,443		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		(13,717)		(5,355)		(11,741)		(11,722)		(29,727)		(2,175)		(10,460)		(13,443)		(1,265)		(99,605)		(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)		3,892		1,337		5,925		7,520		16,779		10,558		4,381		3,412		1,034		54,838		4,076		1,416		6,123		8,430		16,265		10,758		4,968		3,906		855		56,797
Equity-accounted entities
Proved property				9,102		58				1,481				2		1,912				12,555				11,223		71				1,511				2		1,987				14,794
Unproved property				1,045										11						1,056				2,260										11						2,271
Support equipment and facilities				25		6										7				38				19		8										7				34
Incomplete wells and other				364		10				10				19		224				627				945		7				15				19		229				1,215
Gross Capitalized Costs				10,536		74				1,491				32		2,143				14,276				14,447		86				1,526				32		2,223				18,314
Accumulated depreciation, depletion and amortization				(4,543)		(54)				(266)				(19)		(1,052)				(5,934)				(5,287)		(61)				(323)				(20)		(1,124)				(6,815)
Net Capitalized Costs equity-accounted entities (a)(b)				5,993		20				1,225				13		1,091				8,342				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 ~~and €831 million in 2018~~ for the consolidates subsidiaries and €170 million in 2020 and €166 million in 2019 ~~and €180 million in 2018~~ for equity-accounted entities.

(b)

~~Includes Vår Energi AS asset fair value.~~

~~(c)~~

Includes allocation at fair value of the assets purchased by Vår Energi AS.

~~F-147~~F-152

TABLE OF CONTENTS

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)
2019
Italy Rest of
Europe North
Africa Egypt Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
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

(€ 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

2017
Consolidated subsidiaries
Proved property acquisitions 5 5
Unproved property acquisitions
Exploration 31 242 77 110 65 3 76 106 5 715
Development(a)
251 364 785 3,041 1,939 246 714 292 14 7,646
Total costs incurred consolidated subsidiaries 282 606 862 3,151 2,009 249 790 398 19 8,366
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration 1 90 91
Development(b)
2 9 �� 4 48 63
Total costs incurred equity-accounted entities 1 2 9 94 48 154

(a)

Includes the abandonment costs of the assets for €516 million in 2020, €2,069 million in 2019, negative for €517 million in ~~2018, asset for €355 million in 2017.~~2018.

(b)

Includes the abandonment costs of the assets for €424 million in 2020, €838 million in 2019, negative €22 million in ~~2018, negative for €23 million in 2017.~~2018.

(c)

Includes allocation at fair value of the assets purchased by Vår Energi AS.

~~F-148~~F-153

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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 ~~meet~~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~~million.

(b)

Results of operations exclude revenues, DD&A and income taxes associated with ~~3,8~~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.

~~F-149~~F-155

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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		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		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				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		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)		(402)		(488)		(363)		(343)		(974)		(269)		(220)		(234)		(48)		(3,341)
Transportation costs		(8)		(142)		(50)		(11)		(42)		(136)		(7)		(16)				(412)		(8)		(142)		(50)		(11)		(42)		(136)		(7)		(16)				(412)
Production taxes		(171)				(243)				(435)				(191)				(6)		(1,046)		(171)				(243)				(435)				(191)				(6)		(1,046)
Exploration expenses		(25)		(85)		(48)		(22)		(44)		(3)		(79)		(69)		(5)		(380)		(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)		(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)		(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		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)		(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		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						15				257				6		420				698
Total revenues						15				257				6		420				698						15				257				6		420				698
Production costs						(7)				(34)				(2)		(36)				(79)						(7)				(34)				(2)		(36)				(79)
Transportation costs						(1)				(28)						(2)				(31)						(1)				(28)						(2)				(31)
Production taxes						(3)				(26)						(114)				(143)						(3)				(26)						(114)				(143)
Exploration expenses				(6)										(235)						(241)				(6)										(235)						(241)
D.D. & A. and Provision for abandonment						(1)				224				(3)		(222)				(2)						(1)				224				(3)		(222)				(2)
Other income (expenses)				(1)		2				(27)				(25)		(122)				(173)				(1)		2				(27)				(25)		(122)				(173)
Pretax income from producing activities				(7)		5				366				(259)		(76)				29				(7)		5				366				(259)		(76)				29
Income taxes						(3)								(2)		(35)				(40)						(3)								(2)		(35)				(40)
Results of operations from E&P activities of equity-accounted entities				(7)		2				366				(261)		(111)				(11)				(7)		2				366				(261)		(111)				(11)

(a)

Includes asset net impairment amounting to €726 ~~million~~million.

~~F-150~~

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~~Oil~~Proved reserves of oil and natural gas ~~reserves~~

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves ~~follow~~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 ~~2019,~~2020, the average price for the marker Brent crude oil was ~~$63~~$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 companies3931. The description of qualifications of the person primarily responsible of the reserves audit is included in the ~~third party~~third-party audit report4032.

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 ~~2019,~~2020, Ryder Scott Company, DeGolyer and MacNaughton provided an independent evaluation of about ~~31%~~36%33 of Eni’s total proved reserves as of December 31, ~~2019~~42020134, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.

In the three-year period from ~~2017~~2018 to ~~2019, 86%~~2020, 92% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, ~~2019,~~2020, the principal ~~property~~properties which did not ~~subjected to~~undergo an independent evaluation in the last three years ~~was Zohr.~~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

31

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).

32

See “Item 19 – Exhibits”.

33

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%).

34

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%, ~~61%~~57% and ~~60%~~61% of total proved reserves as of December 31, 2020, 2019 ~~2018~~ and ~~2017,~~2018, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves associated with such contracts represented 3%4%, 3% and 4%3% of total proved reserves on an oil-equivalent basis as of December 31, 2020, 2019 and 2018, ~~and 2017,~~ respectively.

39

~~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).~~

40

~~See “Item 19 – Exhibits”.~~

41

~~Including reserves of equity-accounted investments.~~

~~F-152~~

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~~NATURAL GAS~~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.

(billion cubic feet)
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 (137) (64) (419) (551) (210) (99) (198) (24) (36) (1,738)
Sales of Minerals in Place(a)
(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 (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

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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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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.

~~F-156~~F-167

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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-158~~

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

						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.~~factors					45
	Item 4. INFORMATION ON THE COMPANY					2529
	History and development of the Company					2529
	BUSINESS OVERVIEW					3340
	Exploration & Production					3340
	Global Gas & ~~Power .~~LNG Portfolio					5866
	Refining & Marketing and Chemicals .					6369
	Eni gas e luce, Power & Renewables					76
	Corporate and Other activities .					7079
	Research and development .					7179
	Insurance .					7481
	Environmental matters .					7481
	Regulation of Eni’s businesses					8289
	Property, plant and equipment .					8996
	Organizational structure					8996
	Item 4A. UNRESOLVED STAFF COMMENTS .					8996
	Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS					9097
	Executive summary					9097
	Critical accounting estimates					95105
	Group results of operations					97106
	Liquidity and capital resources					~~105~~115
	Recent developments					~~109~~120
	Management’s expectations of operations .					~~110~~120
	Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES					~~119~~129
	Directors and Senior Management .					~~119~~129
	Compensation					~~128~~139
	Board ~~practices.~~practices					~~128~~139
	Employees					~~140~~151
	Share ownership					~~141~~152
	Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS					~~142~~153
	Major Shareholders					~~142~~153
	Related party transactions					~~142~~153
	Item 8. FINANCIAL INFORMATION					~~143~~153
	Consolidated Statements and other financial information .					~~143~~153
	Significant changes					~~143~~155
	Item 9. THE OFFER AND THE LISTING					~~144~~155
	Offer and listing details					~~144~~155
	Markets .					~~144~~156
	Item 10. ADDITIONAL INFORMATION					~~146~~157
	Memorandum and Articles of Association					~~146~~157
	Material contracts					~~153~~164
	Exchange controls					~~153~~164
	Taxation					~~153~~164
	Documents on display					~~158~~169
	Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .					~~159~~169
	Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES					~~162~~172
	Item 12A. Debt securities					~~162~~172
	Item 12B. Warrants and rights					~~162~~172
	Item 12C. Other ~~securities.~~securities					~~162~~172
	Item 12D. American Depositary Shares .					~~162~~172
	PART II
	Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES					~~164~~174
	Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS					~~164~~174
	Item 15. CONTROLS AND ~~PROCEDURES.~~PROCEDURES					~~164~~174
	Item 16. [RESERVED]					~~165~~175
	Item 16A. Board of Statutory Auditors financial ~~expert.~~expert					~~165~~175
	Item 16B. Code of Ethics					~~165~~175
	Item 16C. Principal accountant fees and services .					~~165~~175
	Item 16D. Exemptions from the Listing Standards for Audit Committees .					~~167~~176
	Item 16E. Purchases of equity securities by the issuer and affiliated purchasers					~~167~~177
	Item 16F. Change in Registrant’s Certifying Accountant					~~167~~177
	Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company ~~Manual.~~Manual					~~168~~177
	Item 16H. Mine safety disclosure .					~~170~~179
	PART III
	Item 17. FINANCIAL ~~STATEMENTS.~~STATEMENTS					~~171~~180
	Item 18. FINANCIAL ~~STATEMENTS.~~STATEMENTS					~~171~~180
	Item 19. EXHIBITS					~~171~~180

	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-Absolute~~Net GHG Lifecycle Emissions			~~Overall~~GHG Scope ~~1,2 and Scope~~ 1+2+3 ~~GHG~~ emissions associated with ~~Eni sold products along their~~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 ~~carbon sinks;~~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~~Net Carbon Intensity			Ratio between the ~~net-Absolute~~Net GHG lifecycle emissions and the energy ~~content of~~ products ~~sold.~~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.

	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).

($)	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

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

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

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

	Net wells completed						Wells in progress at 31 Dec.		Net wells completed						Wells in progress at 31 Dec.
	2019		2018		2017		2019		2020		2019		2018		2020
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy	3.0		3.0		2.6		2.0	1.6			3.0		3.0
Rest of Europe	3.3		2.8	0.3	2.7	0.2	25.0	2.2	2.8		3.3		2.8	0.3	24.0	5.0
North Africa	5.0	1.1	9.6	0.5	5.1		2.0	1.1	4.3		5.0	1.1	9.6	0.5	3.0	1.5
Egypt	33.5		30.7		49.7	2.3	9.0	3.5	23.2		33.5		30.7		3.0	1.4
Sub-Saharan Africa	7.0		7.3	0.1	8.6		19.0	3.4	1.2		7.0		7.3	0.1	5.0	0.9
Kazakhstan	0.9		0.9		1.2		1.0	0.3	0.3		0.9		0.9
Rest of Asia	27.3	2.2	21.9		15.0	0.2	25.0	7.9	23.2	0.4	27.3	2.2	21.9		17.0	3.4
Americas	2.1		2.3		3.1		1.0	1.0	2.0		2.1		2.3		6.0	2.0
Australia and Oceania			0.8										0.8
Total including equity-accounted entities	82.1	3.3	79.3	0.9	88.0	2.7	84.0	21.0	57.0	0.4	82.1	3.3	79.3	0.9	58.0	14.2

	Net wells completed						Wells in progress at Dec. 31(1)
	2019		2018		2017		2019
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy		0.5	1.8
Rest of Europe	0.3	1.4		0.5	1.2	1.3	14.0	3.5
North Africa	0.5			0.5	0.5		12.0	9.5
Egypt	4.5	1.5	1.7	1.5	2.5	5.4	13.0	9.7
Sub-Saharan Africa	0.5	0.9	0.4		2.9	0.3	38.0	18.4
Kazakhstan							6.0	1.1
Rest of Asia		1.7	2.2	2.6			11.0	3.8
Americas			4.0		0.5		3.0	1.4
Australia and Oceania		0.5					1.0	0.3
Total including equity-accounted entities	5.8	6.5	10.1	5.1	7.6	7.0	98.0	47.7

	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

	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


ITALY	(1926)	Operated	Adriatic and Ionian Sea: Barbara ~~(100%), Cervia/Arianna~~ (100%), Annamaria (100%), Clara NW (51%), ~~Luna (100%), Angela (100%),~~ 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 ~~(45.24%~~(45.40%), Marulk ~~(13.92%~~(13.97%), Balder & Ringhorne ~~(62.64%~~(62.87%) and Ringhorne East ~~(48.71%~~(48.88%)
		Non-operated	Åsgard ~~(15.35%), Kristin (13.31%), Heidrun (3.60%~~(15.41%), Mikkel ~~(33.67%), Tyrihans (12.54%), Morvin (20.88%~~(33.79%), Great Ekofisk Area ~~(8.62%~~(8.65%), ~~Boyla (13.92%~~Snorre (12.96%), ~~Brage (8.53%~~Ormen Lange (4.43%), Statfjord Unit (14.92%), Statfjord Satellites East (10.16%), Statfjord Satellites North (17.46%), Statfjord Satellites Sygna (14.67%) and ~~Snorre (12.91%~~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~~(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%), ~~South West~~Southwest Meleiha (100%), Baltim (50%), Ras Qattara (El Faras and Zarif – 75%), West Abu Gharadig (Raml – 45%)~~, Ashrafi (50%)~~ and West Razzak (100%)
		Non-operated	Ras el Barr (Ha’py and Seth –— 50%) and South Ghara (25%)
SUB-SAHARAN AFRICA
Angola	(1980)	Operated	~~Block~~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 ~~(Eni 20%~~(20%), Lianzi Development Area ~~Lianzi~~ in the ~~Blocco~~Block 14 K/A IMI (10%) and ~~the~~ Development Areas in the Block 15 (18%)
Congo	(1968)	Operated	Nené Marine (65%), Litchendjili (65%), Zatchi ~~(55,25%~~(55.25%), Loango ~~(42,5%~~(42.5%), Ikalou ~~(100%~~(85%), Djambala (50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%), M’Boundi ~~(82%), Kouakouala (74.25%), Zingali (100%~~(83%) and ~~Loufika (100%~~Kouakouala (75%)
		Non-operated	Pointe-Noire Grand Fond ~~(35%~~(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 ~~(41.6%~~(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%) ~~and~~, Umm Shaif and Nasr (10%) and Area B – Sharjah (50%)
AMERICAS
Mexico	(2019)	Operated	~~Gulf of Mexico~~: 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 ~~Junín~~Junin 5 (40%)

(units)	Oil Wells				Natural gas Wells				Oil Wells				Natural gas Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Italy		204.0		158.2		441.0		383.0		205.0		159.2		396.0		341.6
Rest of Europe		657.0		106.2		207.0		67.0		633.0		109.5		183.0		48.6
North Africa		589.0		245.7		125.0		67.5		612.0		258.1		127.0		67.9
Egypt		1,196.0		513.2		141.0		43.6		1,233.0		527.3		144.0		44.3
Sub-Saharan Africa		2,620.0		538.0		201.0		27.0		2,589.0		524.8		194.0		24.1
Kazakhstan		204.0		55.8		1.0		0.3		207.0		56.7		1.0		0.3
Rest of Asia		990.0		367.7		180.0		63.6		1,012.0		369.5		180.0		60.8
Americas		250.0		128.4		284.0		81.6		253.0		130.6		284.0		81.6
Australia and Oceania						2.0		2.0						2.0		2.0
Total including equity-accounted entities		6,710.0		2,113.2		1,582.0		735.6		6,744.0		2,135.7		1,511.0		671.2


Natural gas sales by entities	2019		2018		2017
	(BCM)
Total sales of subsidiaries		70.39		73.70		77.52
Italy (including own consumption)		37.85		39.03		37.43
Rest of Europe		25.56		27.58		36.10
Outside Europe		6.98		7.09		3.99
Total sales of Eni’s affiliates (Eni’s share)		2.68		3.01		3.31
Italy
Rest of Europe		1.51		1.84		2.13
Outside Europe		1.17		1.17		1.18
Worldwide gas sales		73.07		76.71		80.83


LNG sales	2019		2018		2017
	(BCM)
Europe		5.5		4.7		5.2
Extra European markets		4.6		5.6		3.1
		10.1		10.3		8.3

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

									Ownership %		Balanced refining capacity (Eni’s share) (1) (KBBL/d)		Utilization rate (Eni’s share) %		Conversion index(2) %
	Ownership (%)		Balanced refining capacity (Eni’s share) (KBBL/d)		Utilization rate (Eni’s share)(1) (%)		Conversion index(2) (%)
Wholly-owned refineries				388		89		55				388		66		55
Italy
Sannazzaro		100		200		85		74		100		200		61		73
Taranto		100		104		89		56		100		104		73		56
Livorno		100		84		98		11		100		84		72		11
Partially owned refineries				344		84		57				160		76		52
Italy
Milazzo		50		100		94		60		50		100		78		60
Germany
Vohburg/Neustadt (Bayernoil)		20		41		60		36		20		41		63		36
Schwedt		8.33		19		87		42		8.33		19		94		42
UAE
ADNOC Refining		20		184				63
Total				732		88		56				548		69		54

	Ownership share (%)		Capacity (2019)(a) (ktonnes/y)		Capacity (at regime) (ktonnes/y)		Throughput (2019) (ktonnes/y)
Wholly-owned
Venezia		100		360		560		217
Gela		100		300		750		94
Total biorefineries				660		1,310		311

	Year ended December 31,						Year ended December 31,
Eni Group	2019		2018		2017		2020		2019		2018
	(€ million)						(€ million)
(Profit) loss on inventory		(223)		96		(219)		1,318		(223)		96
Environmental provisions		338		325		208		(25)		338		325
Impairment losses (impairments reversals), net		2,188		866		(221)		3,183		2,188		866
Net gains on disposal of assets		(151)		(452)		(3,283)		(9)		(151)		(452)
Risk provisions		3		380		448		149		3		380
Provision for redundancy incentives		45		155		49		123		45		155
Reinstatement of Eni Norge amortization charges(1)				(375)								(375)
Fair value gains/losses on commodity derivatives		(439)		(133)		146		440		(439)		(133)
Reclassification of currency derivatives and exchange effects to management measure of business performance		108		107		(248)		(160)		108		107
Estimate revision of revenues accrued in the gas retail business						64
Valuation allowance of doubtful accounts(2)		123				616
Credit valuation allowance(2)								77		123
Compensation gain on part of a third-party insurer relating to the EST plant incident		(88)								(88)
Other		261		288		231		77		261		288
Total net non-core items in operating profit		2,165		1,257		(2,209)		5,173		2,165		1,257
Finance expenses		(42)		(85)		502		152		(42)		(85)
of which: reclassification of currency derivatives and exchange effects to management measure of business performance		(108)		(107)		248		160		(108)		(107)
Capital gains on disposal of investments		(46)		(909)		(163)				(46)		(909)
Write downs of investments and financing receivables		166		67		537		1,207		166		67
Write down of deferred tax assets/utilization of deferred tax liabilities		893		99				1,299		893		99
Tax effects relating to the US tax reform						115
Tax effects on the above listed items and other items		(474)		55		160		427		(474)		55
Tax effects on (profit) loss on inventory		66		(27)		63		(381)		66		(27)
Net non-core items in net profit		2,728		457		(995)		7,877		2,728		457
Net (charges) gains attributable to non-controlling interest
Net non-core items attributable to Eni		2,728		457		(995)

(€ million)	before IFRS 16		IFRS 16 effects		GAAP results
Purchases, services and other		(51,908)		1,034		(50,874)
Depreciation, depletion and amortization		(7,276)		(830)		(8,106)
Operating profit		6,228		204		6,432
Finance expense and income taxes		(9,338)		(332)		(9,670)
Net profit		283		(128)		155

Name	Management position	Year first appointed to current position	Total number of years of service at Eni		Age		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		38		64	CEO and General Manager of Eni	2014		39		65
Luca Bertelli	Chief Exploration Officer	2014		35		61
Stefano Maione	Chief Development, Operations & Technology Officer	2019		28		56
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	Chief Services and Stakeholder Relations Officer	2014		36		59	Human Capital & Procurement Coordination Director	2020		37		60
Cristian Signoretto	Chief Gas & LNG Marketing and Power Officer	2019		12		45
Massimo Mondazzi	Chief Financial Officer	2014		27		56
Luigino Lusuriello	Chief Digital Officer	2018		31		58
Giuseppe Ricci	Chief Refining & Marketing Officer	2016		34		61
Alessandro Puliti	Chief Upstream Officer	2019		29		56
Francesca Zarri							Technology, R&D & Digital Director	2020		24		51
Stefano Speroni	Legal Affairs Senior Executive Vice President	2019		1		57	Legal Affairs & Commercial Negotiation Director	2020		2		58
Marco Petracchini	Internal Audit Senior Executive Vice President	2011		20		55	Internal Audit Director(2)	2011		21		56
Roberto Ulissi	Corporate Affairs and Governance Senior Executive Vice President and Board Secretary and Corporate Governance Counsel	2006		13		57	Corporate Affairs and Governance Director and Board Secretary and Corporate Governance Counsel(3)	2006		14		58
Marco Bollini	Commercial Negotiations Senior Executive Vice President	2019		22		53
Marco Bardazzi	External Communication Executive Vice President	2015		4		52
Luca Cosentino	Energy Solutions Executive Vice President	2015		16		58
Erika Mandraffino							External Communication Director	2020		14		47
Lapo Pistelli	International Affairs Executive Vice President	2017		4		55	Public Affairs Director	2020		5		56
Luca Franceschini	Integrated Compliance Executive Vice President	2016		28		53	Integrated Compliance Director(4)	2016		29		54
Jadran Trevisan	Integrated Risk Management Executive Vice President	2016		19		58	Integrated Risk Management Director(5)	2016		20		59

Period	Total number of shares purchased		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs		Total purchase cost		Approximate € value of Shares that may yet be purchased under the plans or programs
			€ per share				(million €)		(million €)
Start of the program June 5 – June 30, 2019		3,690,860		14.21		3,690,860		52		348
1 July – 31 July 2019		5,660,592		14.48		5,660,592		82		266
1 August – 31 August 2019		3,339,795		13.49		3,339,795		45		221
1 September – 30 September 2019		3,543,252		13.96		3,543,252		49		171
1 October – 31 October 2019		5,914,499		13.77		5,914,499		81		90
1 November – 30 November 2019		4,584,298		14.03		4,584,298		64		25
1 December – 31 December 2019		1,857,186		13.65		1,857,186		25		0
Total as of December 31, 2019		28,590,482		13.99		28,590,482		400

		Eni shareholders’ equity
	Note	Share capital		Retained earnings		Cumulative currency translation differences		Other reserves		Treasury shares		Interim dividend		Net profit for the year		Total		Non- controlling interest		Total shareholders’ equity
Balance at December 31, 2018	(25)		4,005		36,702		6,605		1,672		(581)		(1,513)		4,126		51,016		57		51,073
Changes in accounting policies (IAS 28)	(3)				(4)												(4)				(4)
Balance at January 1, 2019			4,005		36,698		6,605		1,672		(581)		(1,513)		4,126		51,012		57		51,069
Net profit for the year															148		148		7		155
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans net of tax effect	(25)								(37)								(37)				(37)
Share of other comprehensive income (loss) on equity accounted investments related to benefit plans remeasurements	(25)								(7)								(7)				(7)
Change of minor investments measured at fair value with effects to OCI	(25)								(3)								(3)				(3)
									(47)								(47)				(47)
Items that may be reclassified to profit or loss in later periods
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)
							604		(488)								116				116
Total comprehensive income (loss) of the year							604		(535)						148		217		7		224
Transactions with shareholders
Dividend distribution of Eni SpA (€0.41 per share in settlement of 2018 interim dividend of €0.42 per share)	(25)												1,513		(2,989)		(1,476)				(1,476)
Interim dividend distribution of Eni SpA (€0.43 per share)	(25)												(1,542)				(1,542)				(1,542)
Dividend distribution of other companies																			(4)		(4)
Allocation of 2018 net income					1,137										(1,137)
Reimbursements to minority shareholders																			(1)		(1)
Acquisition of treasury shares	(25)				(400)				400		(400)						(400)				(400)
					737				400		(400)		(29)		(4,126)		(3,418)		(5)		(3,423)
Other changes in shareholders’ equity
Long-term share-based incentive plan					9												9				9
Other changes					(8)				27								19		2		21
					1				27								28		2		30
Balance at December 31, 2019	(25)		4,005		37,436		7,209		1,564		(981)		(1,542)		148		47,839		61		47,900

(€ million)
Selected line items only	December 31, 2018		Adoption of IFRS 16		Reclassifications IFRS 16		Total effect of the first application		As restated January 1, 2019
Current assets		39,450				(12)		(12)		39,438
of which: Trade and other receivables		14,101				(12)		(12)		14,089
Non-current assets		78,628		5,656		(13)		5,643		84,271
of which: Property, plant and equipment		60,302				(46)		(46)		60,256
of which: Right-of-use assets				5,656		33		5,689		5,689
Assets held for sale		295				13		13		308
Current liabilities		28,382		665		(15)		650		29,032
of which: Current portion of long-term debt		3,601				(16)		(16)		3,585
of which: Current portion of long-term lease liabilities				665		129		794		794
of which: Trade and other payables		16,747				(128)		(128)		16,619
Non-current liabilities		38,859		4,991		(10)		4,981		43,840
of which: Long-term debt		20,082				(36)		(36)		20,046
of which: Long-term lease liabilities				4,991		26		5,017		5,017
Liabilities directly associated with assets held for sale		59				13		13		72

~~(€ billion)~~
~~Future minimum lease payments under non-cancellable operating leases at December 31,~~ ~~2018~~					~~4.0~~
~~- Recognition of the shares of leases related to followers~~					~~2.0~~
~~- Effect of discounting~~					~~(1.5~~)
~~- Extension options~~					~~1.2~~
~~- Other changes~~					~~0.1~~
~~Lease liability at January 1, 2019~~					~~5.8~~

	Nominal value (€ million)		Fair Value (€ million)		Rating – Moody’s	Rating – S&P	Nominal value (€ million)		Fair Value (€ million)		Rating – Moody’s	Rating – S&P
Quoted bonds issued by sovereign states
Fixed rate bonds
Italy		734		743	Baa3	BBB		499		506	Baa3	BBB
Chile		177		181	A1	A+		187		192	A1	A+
Other(*)		216		224	from Aaa to Baa1	from AAA to BBB+		168		172	from Aaa to Baa1	from AAA to A-
		1,127		1,148				854		870
Floating rate bonds
Italy		126		126	Baa3	BBB		253		255	Baa3	BBB
Germany		106		106	Aaa	AAA		56		55	Aaa	AAA
Other(*)		81		82	from Aaa to Baa3	from AAA to BBB
Other								43		43	from Aaa to Baa3	from AA+ to BBB
		313		314				352		353
Total quoted bonds issued by sovereign states		1,440		1,462				1,206		1,223
Other Bonds
Fixed rate bonds
Quoted bonds issued by industrial companies		1,183		1,212	from Aa2 to Baa3	from AA to BBB-		974		992	from Aa2 to Baa3	from AA to BBB-
Quoted bonds issued by financial and insurance companies		862		879	from Aa3 to Baa3	from AA- to BBB-		893		910	from Aa1 to Baa3	from AA+ to BBB-
Other bonds		105		106	from Aaa to Baa2	from AAA to BBB		54		55	from Aaa to Baa3	from AAA to BBB-
		2,150		2,197				1,921		1,957
Floating rate bonds
Quoted bonds issued by industrial companies		1,530		1,535	from Aa1 to Baa3	from AA+ to BBB-		791		787	from Aa1 to Baa3	from AA+ to BBB-
Quoted bonds issued by financial and insurance companies		1,116		1,122	from Aa1 to Baa3	from AA+ to BBB-		1,298		1,301	from Aa1 to Baa3	from AA+ to BBB-
Other bonds		444		444	from Aaa to Baa2	from AAA to BBB		234		234	from Aaa to Baa3	from AAA to BBB-
		3,090		3,101				2,323		2,322
Total other bonds		5,240		5,298				4,244		4,279
Total other financial assets held for trading		6,680		6,760				5,450		5,502

	Performing receivables						Defaulted receivables		Eni gas e luce customers		Total		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		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		1,922		2,882		840		1,396				7,040
National Oil Companies and public administrations		1,201		472		244		2,710				4,627		1,201		472		244		2,710				4,627
Other counterparties		1,646		103		381		217		2,105		4,452		1,646		103		381		217		2,105		4,452
Gross amount		4,769		3,457		1,465		4,323		2,105		16,119		4,769		3,457		1,465		4,323		2,105		16,119
Allowance for doubtful accounts		(13)		(4)		(16)		(2,547)		(666)		(3,246)		(13)		(4)		(16)		(2,547)		(666)		(3,246)
Net amount		4,756		3,453		1,449		1,776		1,439		12,873		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		0.3		0.1		1.1		58.9		31.6		20.1
December 31, 2018
Business customers		2,454		3,585		1,152		1,350				8,541
National Oil Companies and public administrations		1,292		157		672		2,217				4,338
Other counterparties		1,494		77		156		271		2,374		4,372
Gross amount		5,240		3,819		1,980		3,838		2,374		17,251
Allowance for doubtful accounts		(9)		(3)		(44)		(2,237)		(857)		(3,150)
Net amount		5,231		3,816		1,936		1,601		1,517		14,101
Expected loss (% net of counterpart risk mitigation factors)		0.2		0.1		2.6		62.5		36.1		18.3

	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, 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
December 31, 2018
Customers – Eni gas e luce:
- Retail		575		49		34		64		554			1,276
- Middle		449		43		13		29		349			883
- Other		207		2		1		2		3			215
Gross amount		1,231		94		48		95		906	��		2,374
Allowance for doubtful accounts		(20)		(18)		(18)		(56)		(745)			(857)
Net amount		1,211		76		30		39		161			1,517
Expected loss (%)		1.6		19.1		37.5		58.9		82.2			36.1

(€ 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		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		1,274		42,856		3,901		1,267		9,195		1,809		60,302
Additions		12		144		223		508		6,170		992		8,049		12		144		223		508		6,170		992		8,049
Depreciation capitalized								14		202				216								14		202				216
Depreciation (*)		(60)		(6,435)		(537)								(7,032)		(60)		(6,435)		(537)								(7,032)
Reversals		44		65		69				65		139		382		44		65		69				65		139		382
Impairment		(47)		(659)		(500)				(669)		(537)		(2,412)		(47)		(659)		(500)				(669)		(537)		(2,412)
Write-off						(5)		(216)		(49)				(270)						(5)		(216)		(49)				(270)
Disposals		(1)		(3)		(1)		(22)		(80)		(6)		(113)		(1)		(3)		(1)		(22)		(80)		(6)		(113)
Currency translation differences		2		815		21		24		181		1		1,044		2		815		21		24		181		1		1,044
Initial recognition and changes in estimates				2,028				25		21				2,074				2,028				25		21				2,074
Transfers		42		7,568		597		(42)		(7,526)		(639)				42		7,568		597		(42)		(7,526)		(639)
Other changes		(48)		113		(136)		5		(98)		116		(48)		(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		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		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		2,849		98,297		24,559				3,994		924		130,623
2018
Net carrying amount – beginning of the year		1,313		45,782		3,877		1,371		9,469		1,346		63,158
Additions		18		432		173		330		6,947		878		8,778
Depreciation (*)		(65)		(6,012)		(529)								(6,606)
Reversal		41		299		86								426
Impairment		(61)		(477)		(73)				(548)		(117)		(1,276)
Write-off				(12)		(1)		(66)		(4)		(1)		(84)
Disposals		(2)		(400)		(9)		(32)		(198)		2		(639)
Currency translation differences		2		1,623		36		53		385		(1)		2,098
Changes in the scope of consolidation		1		(4,388)		32		(58)		(474)		10		(4,877)
Transfers		81		6,795		461		(294)		(6,501)		(542)
Other changes		(54)		(786)		(152)		(37)		119		234		(676)
Net carrying amount – end of the year		1,274		42,856		3,901		1,267		9,195		1,809		60,302
Gross carrying amount – end of the year		4,060		135,467		27,516		1,267		12,559		2,415		183,284
Provisions for depreciation and impairments		2,786		92,611		23,615				3,364		606		122,982

(%)
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

(€ 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		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		3,294		346		569		462		7			720		43		215		5,656
Reclassifications								30								16		46								30									16		46
Reclassifications to assets held for sale																(13)		(13)																	(13)		(13)
Net carrying amount at January 1, 2019		3,294		346		569		492		7		720		43		218		5,689		3,294		346		569		492		7			720		43		218		5,689
Additions		32		192		219		54		1		108		22		56		684		32		192		219		54		1			108		22		56		684
Depreciation(a)		(240)		(224)		(272)		(61)		(1)		(115)		(23)		(63)		(999)		(240)		(224)		(272)		(61)		(1)			(115)		(23)		(63)		(999)
Impairment losses								(13)								(28)		(41)								(13)									(28)		(41)
Currency translation differences		67		6		4		2				3				3		85		67		6		4		2					3				3		85
Other changes				(7)		(23)		(14)		(1)		(9)		(10)		(5)		(69)				(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		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		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		240		215		260		72		1			99		22		93		1,002

(€ million)	Trade payables		Down payments and advances from joint ventures in exploration and production activities		Other payables		Total trade and other payables
Carrying amount at December 31, 2018		11,645		207		4,895		16,747
Changes in accounting policies (IFRS 16)		(128)						(128)
Carrying amount at January 1, 2019		11,517		207		4,895		16,619

(€ million)	December 31,2019		December 31,2018
Trade payables		10,480		11,645
Down payments and advances from joint ventures in exploration & production activities		401		207
Payables for purchase of non-current assets		2,276		2,530
Payables due to joint ventures in exploration & production activities		1,236		1,151
Other payables		1,152		1,214
		15,545		16,747

	Long-term debt
(€ million)	2021		2022		2023		2024		After		Total
Banks		750		146		838		134		473		2,341
Ordinary bonds		930		698		1,879		1,641		10,989		16,137
Convertible bonds				393								393
Other financial institutions		11		13		14		1				39
		1,691		1,250		2,731		1,776		11,462		18,910