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

The Group’s activities depend heavily on the reliability and security of its information technology (IT) systems and digital security. The Group’s IT systems, some of which are managed by third parties, are susceptible to being compromised, damaged, disrupted or shutdown due to failures during the process of upgrading or replacing software, databases or components, power or network outages, hardware failures, cyber-attacks (viruses, computer intrusions), user errors or natural disasters. The cyber threat is constantly evolving. The oil and gas industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. Attacks are becoming more sophisticated with regularly renewed techniques while the digital transformation amplifies exposure to these cyber threats. The adoption of new technologies, such as the Internet of Things (IoT) or the migration to the cloud, as well as the evolution of architectures for increasingly interconnected systems, are all areas where cyber security is a very important issue. The Group and its service providers may not be able to prevent third parties from breaking into the Group’s IT systems, disrupting business operations or communications infrastructure through denial-of-service attacks, or gaining access to confidential or sensitive information held in the system. The Group, like many companies, has been and expects to continue to be the target of attempted cybersecurity attacks. While the Group has not experienced any such attack that has had a material impact on its business, the Group cannot guarantee that its security measures will be sufficient to prevent a material disruption, breach or compromise in the future. As a result, the Group’s activities and assets could sustain serious damage, services to clients could be interrupted, material intellectual property could be divulged and, in some cases, personal injury, property damage, environmental harm and regulatory violations could occur.

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.

Violations of data protection laws carry fines and expose us and/or our employees to criminal sanctions and civil suits.

Data protection laws and regulations apply to Eni and its joint ventures and associates in the vast majority of countries in which we do business. The EU General Data Protection Regulation (GDPR) came into effect in May 2018, which increased penalties up to a maximum of 4% of global annual turnover for breach of the regulation. The GDPR requires mandatory breach notification, the standard for which is also followed outside 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.

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

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

Exposure to the commodity risk has been described in the paragraph above. 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 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, ~~activities involve~~this activity involves elements of forecasting and Eni is exposed to the risks ~~of market movements,~~ of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.

~~Exchange rate risk~~

~~Movements~~

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We are exposed to exchange risks because our consolidated financial statements are prepared in Euros, whereas our main subsidiaries in the Exploration & Production sector are utilizing the US dollar as functional currency. Furthermore, our subsidiaries hold assets and are exposed to liabilities in other currencies, mainly the US dollar. Therefore, movements in the USD versus the euro exchange rate affect year-on-year comparability of ~~the euro against the U.S. dollar can have a material impact on Eni’s~~ results of ~~operations. Prices~~operations and cash flows. Furthermore, prices of oil, natural gas and refined products generally are denominated in, or linked to, ~~U.S. dollars,~~USD, while a significant portion of Eni’s expenses are incurred in euros. Accordingly, a depreciation of the ~~U.S. dollar~~USD against the euro generally has an adverse impact on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in ~~U.S. dollar-denominated~~USD denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity. The Exploration & Production segment is particularly affected by movements in the dollar versus the euro exchange rates as the U.S. dollar is the functional currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations.

~~Susceptibility to variations in sovereign rating risk~~

Eni’s credit ratings are potentially exposed to risk infrom possible reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the ~~Notes or other~~ debt instruments issued by the Company could be downgraded.

~~Interest rate risk~~

Interest on Eni’s debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, “Euribor”, and the London Interbank Offered Rate, “Libor”. As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its debt. Additionally, spreads offeredWe are exposed to the ~~Company may rise~~liquidity risk in ~~connection with variations in sovereign rating risks or company rating risks, as well as~~case the ~~general conditions of capital markets.~~

~~Liquidity risk~~

~~Liquidity risk is the risk that~~Group fails to access suitable sources of funding, ~~for the Group may not be available,~~ or 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 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. ~~European and global~~Global financial markets are ~~currently subject to volatility amid uncertainties relating~~volatile due to a ~~weak~~number of macroeconomic ~~outlook, particularly in the Euro-zone, and~~risk factors, including the financial ~~stress~~situation of certain ~~emerging economies or~~hydrocarbons-exporting countries whose financial conditions ~~depends upon~~have sharply deteriorated following the ~~proceeds of the sale of hydrocarbon resources following a prolonged slump~~protracted downturn in ~~commodity~~crude oil prices. 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, Eni’s ability to maintain Eni’s long-term investment program may be impacted with a consequent effect on Eni’s ~~growth rate,~~business prospects and ~~may impact shareholder returns, including dividends or share price.~~results of operations and cash flows.

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 ~~exploitation~~ and production of oil and natural gas reserves. ~~The Company’s~~In 2020, Eni expects to make capital ~~budget for the four-year plan 2017-2020 amounts to €31,6~~expenditures of approximately €4 billion ~~net of capex associated with~~at the planned ~~asset disposals, and is significantly lower than the Group’s previous industrial plan (down by an estimated 8% at constant~~ exchange ~~rates) as a result~~rate of a planned reduction in spending prompted by weak commodity prices and a more selective approach to spending compared to the past. The Company has budgeted approximately €7.8 billion for capital expenditure in 2017, which is 18% lower than in 2016 at constant exchange rates. Management may find that additional reductions in Eni’s capital budget become necessary depending on market conditions.

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1.12 USD/EUR. Historically, Eni’s capital expenditures have been financed with cash generated by 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 ~~equipments,~~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 ~~financial condition,~~prospects, results of operations and cash ~~flows and its ability to achieve its growth plans.~~

With respect to the 2017-2020 business plan in particular, management expects to deliver approximately €5-7 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of stakes in the Group’s exploration assets thereby in essence monetizing some of the Group’s recent exploration successes and reserves. These additional cash flows are intended to provide the Group with further financial flexibility in view of funding organic growth and the Group’s planned shareholder distributions in a manner consistent with the Group’s target capital structure. The Company is seeking to complete such disposals in large part within 2017. However, asset disposals are subject to execution risk and may fail to be completed, and the proceeds received from such disposals may not reflect valuations that management currently believes are achievable, particularly if the disposals are carried out in difficult market conditions. The failure to achieve the planned disposal program could negatively affect the achievement of the Group’s financial targets forcing us to either curtail capital expenditure thus hampering growth or take on more finance debt.

~~These factors could also negatively affect shareholders’ returns, including the amount of cash available for dividend distribution as well as the share price.~~

flows. 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, thereby reducing its ability~~debt.

We are exposed to ~~use cash flows~~credit risk; our counterparties could fail or could be unable to ~~fund capital expenditures~~pay the amounts owed to us and ~~dividends.~~

~~Credit risk~~

~~Credit risk is the potential exposure of the Group~~ to ~~losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones.~~meet their performance obligations under contractual arrangements. In the ~~latest~~last few years, the Group has experienced a level of counterparty default higher than in previous years due to

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the severity of the economic and financial downturn that has negatively affected several Group counterparties, customers and the amount of trade receivables overdue at the balance sheet date has increased significantly. Furthermore, a collapse in oil prices has stressed the financial condition of many State-owned entities, which are partypartners and to the ~~Group’s upstream projects for exploring~~fact that Italy, which is still the largest market to Eni’s gas wholesale and ~~developing hydrocarbons or are buyers~~retail businesses, has underperformed other OECD countries in terms of ~~Eni’s equity production. In the 2016 Consolidated Financial Statements, we accrued an allowance against doubtful trade accounts amounting to €503 million, mainly relating to~~GDP growth. Management believes that the Gas & Power ~~business~~ segment ~~in relation to Italian retail customers who were experiencing financial difficulties. Management believes that this business~~ 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 have been particularly ~~impacted~~hit by the financial and economic downturn. Going forward, we expect that an uncertain macroeconomic outlook in Europe and Italy will pose a risk to the Company’s ability to collect revenues in its retail gas and power business. Eni’s E&P business is significantly exposed to the credit risk because of the deteriorated financial outlook of many oil-producing countries due to continued weak oil prices, 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 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 receivable or its investments towards those entities. For further information, see the paragraph “Political Considerations” above. Eni believes that

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the management of doubtful accounts represents an issue to the Company, which will require management focus and commitment going forward. ~~In the future~~ Eni cannot exclude the recognition of significant provisions for doubtful ~~accounts. Considering~~accounts in the ~~deteriorated financial outlook of many oil-producing countries where Eni is conducting its upstream operations due to a prolonged decline in commodity prices,~~future. In particular, management is ~~strictly~~closely monitoring exposure to the counterpart risk in its Exploration & Production (“E&P”) segment. The financial difficulties of certain countries also involve state-owned oil companies who are partnering Eni in the execution of development projects of hydrocarbons reserves or who are buying Eni’s share of production in joint projects. In 2016, we incurred approximately €0.4 billion of losses relateddue to the ~~expected outcome~~magnitude of ~~certain renegotiations to settle disputed amounts or to establish repayment plans of certain overdue receivables owed by few National Oil Companies. Due~~the exposure at risk and to the ~~prolonged~~long-lasting effects of the oil price downturn on its industrial partners.

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 ~~downturn~~condition, and shareholder returns, including dividends, the amount of ~~certain countries hit by a fall in petroleum revenues, it is possible that~~funds available for stock repurchases and the ~~Group may incur further counterparty losses in the future. For further information see the paragraph “Political Considerations” above.~~

~~Digital infrastructure is an important part of maintaining Eni’s operations. A breach~~price of Eni’s ~~digital security could result in serious damage to business operations, personal injury, damage to assets, harm~~share.

See “Liquidity and capital resources” on page 105 and Note 27 – Financial Risk – to the ~~environment, breaches of regulations, litigation, legal liabilities and reparation costs~~

The reliability and security of Eni’s digital infrastructure is critical to maintaining the availability of Eni’s business applications, including the reliable operation of technology in Eni’s various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. If Eni’s systems for protecting Eni’s digital security prove to be ineffective, either due to intentional actions such as cyber-attacks or negligence, Eni could be adversely affected by, among other things, loss or damage to intellectual property, proprietary information, or customer data, an interruption of business operations, and increased costs to prevent, respond to, or mitigate potential risks to Eni’s digital infrastructure. Furthermore, in some circumstances, failures to protect digital infrastructure could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.“Consolidated Financial Statements”.

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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. In 2016, the Group exited the Engineering & Construction segment by divesting an interest of 12.503% in the segment parent company, Saipem. Simultaneously to that divestment the Group signed a shareholder agreement with the acquirer that established joint control over Saipem. As a result of those transactions, Eni derecognized Saipem’s assets and liabilities, revenues and expenses effective January 1, 2016. The retained interest of 30.55% in Saipem has been accounted for as an equity-accounted investment from the transactions date. Eni has operations in 7366 countries and ~~33.536~~32,053 employees as of December 31, ~~2016.~~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 ~~Giovan Battista Di Giovanni,~~Marco Margheri, Washington DC – USA 601, ~~13th~~13th street, NW 20005.

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 4441 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Australia, ~~Venezuela,~~ Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and ~~Mozambique.~~United Arab Emirates. In ~~2016,~~2019, Eni average daily production amounted to ~~1,671~~1,736 KBOE/d on an ~~available-for-sale~~available- for-sale basis. As of December 31, ~~2016,~~2019, Eni’s total proved reserves amounted to ~~7,490~~7,268 mmBOE, which include subsidiary undertakings and Eni’s share of reserves of equity-accounted and proportionally consolidated entities.

Eni’s Gas & Power segment engages in the supply, trading and marketing of gas, LNG and electricity, international gas transport activities and commodity trading and derivatives. This segment also includes the activity of electricity generation that is ancillary to the marketing of electricity. In ~~2016,~~2019, Eni’s worldwide sales of natural gas amounted to ~~88.93~~73.07 BCM, of which ~~38.43~~37.85 BCM in Italy. Eni produces power at a number of operated ~~gas-fired~~gas- fired plants in Italy with a total installed capacity of 4.7 GW as of December 31, ~~2016.~~2019. In ~~2016,~~2019, electricity sold ~~totaled 37.05~~totalled 39.49 TWh. The LNG business includes the purchase and marketing of LNG worldwide, with a large incidence 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 ~~and~~ of asset-backed trading ~~activities. Through the trading department of the parent company~~activities and its wholly-owned subsidiary Eni Trading & Shipping SpA, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. This activity is designated to hedge part of the Group exposure to the commodity risk and to optimize commercial margins by entering speculative derivative transactions.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 the results of operations of the R&M business and of the chemicals business which have been combined in a single reporting segment because the two businesses exhibit similar characteristics.

The R&M business engages in crude oil supply and refining and marketing of petroleum products in retail and wholesale markets mainly in Italy and in the rest of ~~Europe.~~Europe, as well as in the petrochemical business. As of December 31, 2019, balance refining capacity was 732 KBBL/d including our share of capacity at ADNOC Refining (UAE) where we acquired a 20% interest in 2019. In ~~2016,~~2019, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to ~~24.73~~23.05 mmtonnes (of which traditional refinery throughputs were ~~24.52~~22.74 mmtonnes and ~~green~~bio refinery throughputs were ~~0.21~~0.31 mmtonnes) and sales of refined products were ~~33.41~~32.27 mmtonnes, of which ~~25.6~~25.56 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to ~~8.59~~8.25 mmtonnes in Italy and in the rest of Europe. In ~~2016,~~2019, Eni’s retail market ~~share~~shares in Italy through its “Eni” branded network of service stations was ~~24.3%~~23.7%.

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~~Through~~In the Chemical business Eni, through its wholly-owned subsidiary Versalis, ~~the Group~~ 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. ~~The four-year industrial plan foresees the start-up of joint ventures for the production of elastomers in East Asia.~~ In ~~2016,~~2019, production volumes of

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petrochemicals amounted to ~~5,646 Ktonnes.~~

8,068 ktonnes. The results of Versalis have been aggregated with those of R&M, in the reportable segment “R&M and Chemicals” because the two ~~segments~~businesses exhibit similar economic characteristics.

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

Eni branches are located in:

•

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

•

San Donato Milanese (Milan), Piazza Ezio Vanoni, 1.

Internet address: eni.com

A list of Eni’s subsidiaries is provided in “Item 18 – ~~note 48~~Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements”.

Strategy

~~Eni’s~~The Company has taken steps to adapt to and thrive in a low-carbon world. We have designed a long-term strategy ~~is reflective~~for the evolution of our Company over the next thirty years. This evolution and the underlying actions plan aim at maximizing the economic opportunities arising from a ~~deteriorated commodity price environment. During the oil downturn, we have managed to be more selective~~fast changing energy market while delivering a deep reduction in GHG emissions from our capital investment decisions, to dispose of non-strategic assets, to boost efficiency across all business lines, to renegotiate contracts, to right-size refinery and chemical plants capacity and to streamline processes, operations and ~~G&A. In 2016, we reduced~~ our ~~capital expenditure by 19% y-o-y, mainly~~products.

The principles that are the basis of our business strategy and will drive the evolution of our portfolio are:

•

to actively contribute to the achievement of all 17 UN SDGs which are reflected in ~~our E&P segment with negligible impacts on our production levels. In spite~~Eni’s mission;

•

to maximize the integration of the ~~severity~~portfolio along the entire value chain, from production to final sale of the oil price contraction, which has lost about two thirds of its value from its highs in 2014 compared to the average value registered in 2016, the ratio of net borrowings to total shareholders’ equity, including non-controlling interests, was 0.28 at 2016 year-end below the management 0.3 ceiling. For further information see “Item 5 – Liquidity.”conventional, bio and renewable products;

~~Our priority in the next few years is to increase cash-flow generation, through growing profitably in E&P and enhancing our mid and downstream businesses. We will continue~~

•

to focus on capital discipline ~~effective management~~to maintain a strong balance sheet and to sustain our cash flow generation; and

•

to maintain a progressive shareholder remuneration policy.

In our evolution path we design a more integrated and sustainable Company, which will be able to compete effectively in the global energy market leveraging on its existing asset base, technologies and competencies and the ongoing development of the ~~time-to-market~~new businesses of renewables and circular economy.

On the basis of the four firm principles, operational strategies have been defined for 2035 and 2050, which outline the evolutionary and integrated path of all of our ~~reserves, early monetization~~business units. The speed of ~~discovered resources through~~evolution and the ~~disposal~~relative contribution of ~~interests~~each business will depend on market trends, technological developments and legislation and the success of our implementation of the strategy in each business. Our goals for each businesses are follows:

In the E&P business:

•

to strengthen the resiliency of our portfolio of conventional oil&gas assets, which are expected to be characterized by a low breakeven, a fast time to market and a limited exposure beyond the medium term;

•

to grow production at an average rate of 3.5% till 2025. After this year, we expect production to start a flexible decreasing trend mainly in its oil part. At the same time, we will seek to retain the ability to modulate future investments in exploration ~~assets~~ and cost control. Our four-year plan foresees a capital budget of approximately €31.6 billion, which is 8% lower than the previous plan, while we are revising upwardly our long-term Brent price assumptionsdevelopment to 70 $/barrel, up from a previous 65 $/barrel. This capital budget is reflective of our cautious stance about future trends in the oil market. Going forward, we will retain a low level of cash neutrality, i.e. we have identified actions and initiatives which should enable the Company to ~~fund its planned capital expenditures via cash flow from operations in~~capture market opportunities as they evolve. We expect to produce the vast majority of the value of our reserves by 2035 assuming a ~~low~~flat Brent price ~~environment. Our key financial objectives are disclosed under “Item 5 – Management’s expectations~~scenario of ~~operations”.~~$50/bbl. The gas share of production is expected to reach 60% by 2030 and around 85% in 2050;

~~Our strategic guidelines are described below.~~

•

Into invest significantly in exploration activities with a view of increasing the ~~Exploration & Production segment, we plan to achieve profitable production growth to boost cash generation. New field start-ups, ramp-ups at our current field~~geographical diversification and production optimization to fight natural depletion will underpin our production targets at 2020. Exploration will be the main driver of our future growth and reserve replacement. It will also boost cash generation through early monetization of discovered resources, as it was the case with the Zohr 40% divestment, which is expected to be completed in 2017. Phased project development, designed to reduce financial exposure and fasten production start-up, effective managementoptionality of the ~~time-to-market of our capital projects~~portfolio; and ~~cost control will sustain~~

•

to grow the cash generation.

In the renewables business:

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

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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.

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In the Gas & Power ~~R&M~~business:

•

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

•

to achieve a complete transition to bio and renewable products by 2050;

•

to enhance the offer to customers with the supply of new services;

•

to capture synergies by centralizing in this business the activity of marketing and trading of all non-oil commodities;

•

to focus on equity products marketing (gas, biomethane, blue energy, hydrogen) and the progressive reduction of non-equity gas sales; and

•

to support production of electricity at existing power plants with the construction of CO2 capture and storage capacity, targeting the offset of over 10 million tons per year by 2050, with a first project under study for the Ravenna hub in Italy.

In the Refining & Marketing:

•

to continue the process of feedstock diversification in our ~~priority is~~running bio-refineries to become “palm oil free” by 2023, 7 years ahead of the EU ban on palm oil;

•

to expand production capacity for bio-fuels to over 5 million tonnes per year, utilizing exclusively 2nd and 3rd generation. We are planning to target areas such as the Far and Middle East, Europe for bio-jet fuel production and the United States;

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to progressively convert traditional Italian refining sites through the construction of new plants for the production of hydrogen, methanol, bio-methane and products coming recycle of waste materials;

•

in the long-term to retain ~~profitable and cash-generative operations against~~just one traditional refinery in operation, the ~~backdrop of structural headwinds~~Ruwais refinery in the ~~competitive environment~~United Arab Emirates, leveraging its optimal geographic location and operational efficiency;

•

to evolve the product mix marketed at our retail outlets, reaching 100% of de-carbonized products by 2050; and

•

to increase the offer of additional services to improve margins and enhance customer loyalty.

In the Chemical business:

•

to enhance production of high-quality and high-performance polymers;

•

to develop and integrate the new businesses of producing chemicals products from renewables and from chemical recycling and mechanical recycling of wasted plastics;

•

to develop the business of producing polymers via pyrolysis of non-recyclable plastics to obtain products with same characteristics as those produced by hydrocarbons; and

•

to establish an integrated platform to maximize synergies with refining in gasification processes involving all types of plasmix.

Finally, we are committed to executing projects for the conservation of primary and secondary forests, which based on our estimates will be able to offset CO2 emissions exceeding 30 million tons per year by 2050.

We expect the above-described industrial actions coupled with the results of the planned projects for forest conservation and projects of CO2 capture and storage will drive a reduction of 80% in net scope 1, 2 and 3 emissions, with reference to the entire life-cycle of the energy products sold and a 55% reduction in emission intensity compared to 2018.

We also expect to reach the net carbon neutrality target for scope 1 and 2 emissions in the E&P business relating to equity production by 2030 and net carbon neutrality for scope 1 and 2 emissions for the entire Eni group by 2040.

Carbon footprint

The strategy and the actions plans designed by the Company will drive a significant improvement in our carbon footprint and a large reduction in emissions, with the achievement of long-term targets of carbon containment supported by for the continued advances and progress that we expect to achieve in the short and medium-term.

To measure our emissions, we have adopted a new fully comprehensive approach, along the value chain, taking into account the GHG emissions from all energy products traded by our organization.

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Therefore, 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 for energy-related CO2 in its SDS scenario that is commonly considered the main benchmark for the achievement of the goals of the Paris Agreement;

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

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

Our carbon footprint reduction will be driven by:

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

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

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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 up to 40 Mtons per year of CO2.

In 2019 we reduced the carbon intensity in our E&P business to 19.58 tonnes of CO2 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 1 and 2 emissions in our upstream business (on equity basis) by:

– increasing efficiency to minimize direct upstream CO2 emissions. As part of this target by 2025 we plan to eliminate gas process flaring and reduce methane emissions by 80%; and

– offsetting residual upstream emissions through large forestry projects.

Furthermore, we expect net carbon intensity to drop by around 15% by 2035 and 55% by 2050, benefitting also from 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 for the Eni Group by 2040.

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% of Eni’s production in 2019 on an available-for-sale basis; as of December 31, 2019, gas reserves represented approximately 50% 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. We believe that those elements of our portfolio will mitigate the risk of stranded reserves going forward due to ~~expectations~~risks of ~~sluggish trends~~lower hydrocarbons demand in ~~commodity demand, strong competition~~response to stricter global environmental constraints and ~~oversupplies/overcapacity. The achievement~~regulations and increasing public sensitivity to the issue of ~~this goal will require continued initiatives~~global warming. Eni’s portfolio exposure to those risks is reviewed annually against changing GHG regulatory regimes and physical conditions to identify emerging risks. To test the resilience of ~~business enhancement and improvement.~~new capital projects, Eni assesses potential costs associated with GHG emissions when evaluating all such projects. 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, while retaining the management scenario for

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~~In executing this strategy,~~hydrocarbons prices; and ii) the hydrocarbon prices and cost of CO2 emissions adopted in the International Energy Agency (IEA) Sustainable Development Scenario “IEA SDS”. This stress test is performed on a regular basis, to monitor the progress of each project. The review performed at the end of 2019 indicated that the internal rates of return of Eni’s ongoing projects in aggregate should not be substantially affected by a carbon pricing mechanism, even assuming that carbon costs are not recoverable in the cost oil and non- deductible from profit before taxes. The project development process features a number of checks that may require the development of detailed GHG and energy management ~~intends~~plans. The majority of the projects have GHG intensity targets that allow them under current assumptions to ~~pursue integration opportunities among segments,~~compete in a more CO2 regulated future. These processes can lead to projects being stopped, designs being changed, and ~~within each segment~~potential GHG mitigation investments being identified, in preparation for when the economic conditions imposed by new regulation would make these investments commercially compelling.

Furthermore, management performed a review of the recoverability of the book values of the Company’s oil & gas assets under the assumptions set forth in the IEA SDS WEO 2019. This review covered all of the oil & gas cash generating unit (CGUs) that are regularly tested for impairment in accordance to ~~focus strongly on efficiency improvement through technology upgrading, cost efficiencies, commercial~~IAS 36. The IEA SDS sets out an energy pathway consistent with the goal of achieving universal energy access by 2030 and ~~supply optimization~~of reducing energy-related CO2 emissions and ~~continuing process streamlining across all segments.~~

~~Finally, we are reaffirming our commitment to a progressive dividend policy,~~air pollution in line with ~~our plans~~the goals of ~~underlying earnings~~the Paris Agreement. To reach these targets, the IEA SDS forecast a peak in global CO2 emissions by 2025, an average decline of 4% per year after that peak and ~~cash flow~~net zero emissions in 2070. Global energy demand is forecast to decline at a small pace notwithstanding the assumptions of continued economic growth and universal access to energy by 2030. 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 hydrocarbons pricing assumptions of the IEA SDS scenario ~~evolution.~~are slightly lower than Eni’s pricing assumptions regarding crude oil (for example in 2040 the price of crude oil is projected to be 10% lower 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. 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 CO2 emissions costs as estimated by the IEA SDS would reach up to 140 $ per ton in real terms 2018 (referred to Advanced Economies), 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 the resiliency of Eni’s asset portfolio in terms of carrying amounts and fair value, determining a reduction of 7% in the total fair value 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 financial statements. That reduction falls to a 2% decline assuming the recoverability of CO2 costs in the cost oil or the deductibility from the taxable income.

~~For a description~~Furthermore, management assessed the recoverability of ~~risks and uncertainties~~the expected costs associated with the Company’s ~~outlook~~plans to ramp up the participation in projects for forestry conservation and protection from degradation, which is one of the ~~capital expenditure program see “Item 5 – Operating~~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 ~~financial review and prospects – Management’s expectations~~2” carbon emissions of ~~operations”.~~

~~Significant~~the E&P business ~~and portfolio developments~~

~~The significant business and portfolio developments that occurred in 2016 and to date in 2017 were the following:~~

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~~Eni signed two preliminary agreements with Bp and Rosneft~~calculated on equity production for the ~~disposal~~achievement of ~~a 40% interest in~~ the ~~important gas Zohr discovery, located in~~carbon neutrality of the operated block of Shoruk (Eni’s interest 100%) off Egypt. These transactions confirm the effectiveness of Eni’s “dual exploration model”, which simultaneously targets the fast-track development of discovered resources, while reducing stakes retained in exploration leases in order to monetize in advancebusiness from 2030 onwards. Those costs are considered part of the ~~discovered volumes~~operating expenses of the E&P business and ~~reduce expenditures~~their recoverability has been evaluated in ~~development process. These agreements have economic efficacy from January 1, 2016 and contemplate~~relation to the ~~reimbursement to Eni of capex incurred until~~CGU E&P segment as a whole. When including those costs extrapolated along the ~~closing date. The new partners have the option to acquire a further 5% stake at the same terms defined~~reserves residual life in the ~~agreements. The first transaction closed on February 2017 following approval~~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 ~~Egyptian authorities;~~Company in the ~~second one with Rosneft is expected to close~~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 ~~first half~~trend in the recognition of ~~2017. The total consideration~~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 of the ~~deal amounts~~sector: the increased volatility of crude oil prices which have been increasingly exposed to ~~approximately €2 billion as of January 1, 2017, including~~macro and global risks; the ~~reimbursement of costs incurred by Eni in 2016.~~

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March 2017: Eni and Gazprom signed a Memorandum of Understanding aiming to analyze the prospects for cooperation in developing the Southern corridor for gas supplies from Russia to European countries, including Italy, as well as the updating of the Russia-Italy gas supply agreements. The Memorandum also provides for the analysis of partnershipscontinued oversupply in the ~~LNG sector.~~

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~~March 2017: Eni and ExxonMobil signed~~oil markets which has determined a ~~sale and purchase agreement to acquire a 25% indirect interest~~reset in the Area 4 block, offshore Mozambique. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The agreed terms include a cash price of approximately $2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Following completion of the transaction, Eni East Africa will be co-owned by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by and CNPC. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore. This operating model will enable the use of best practices and skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project.

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March 2017: finalized a farm-in agreement to acquire a 50% interest of Block 11, Offshore Cyprus, which will be operated by Total. The exploration area covers 2,215 square kilometers, nearby the Zohr discovery in the Egyptian offshore. Block 11 is expected to be drilled within 2017.

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February 2017: started-up the Cabaça South East field of the East Hub Development Project, in Block 15/06 of the Angolan deep offshore, five months ahead of development plan estimates and with a very good time-to-market. Block 15/06 will reach a peak of 150 KBBL/d this year.

•

January 2017: successfully drilled an appraisal well of the Merakes discovery under the Production Sharing Contract (PSC) in East Sepinggan. This discovery is located 35 kilometers from the Eni operated Jangkrik field, close to starting operations.

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January 2017: made a discovery in the PL128/128D licenses in the Norwegian Sea nearby the FPSO (Floating Production, Storage and Offloading) operating the Norne field. This discovery is part of Eni’s near-field exploration strategy aimed at unlocking the presence of additional resources in proximity to existing infrastructures.

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~~January 2017: awarded three new exploration licenses~~hydrocarbons realized prices and cash flows of oil companies; growing uncertainty about long-term evolution of the global oil demand in ~~Norway, as a~~light of the rising commitment on part of the ~~APA Round.~~international community at fighting the climate change and speeding up the pace of the energy transition, the increase in energy alternatives to fossil fuels and changing consumers’ preferences, management has evaluated the recoverability of the book values of Eni’s oil&gas properties at different stress-test scenarios, including the risk of stranded assets. Particularly, under the more conservative set of the assumptions which envisages a flat long-term Brent price of 50 $/bbl and at a flat Italian gas price of 5 $/mmBTU, management is estimating that approximately 85% of the Company’s proven and probable/possible reserves (risked at 70% and 30% respectively) will be produced within 2035 and 94% of their net present value will be realized. The net present value of those production volumes, valorized at the most conservative of the scenarios evaluated, is substantially aligned with the book values of the net fixed assets of Eni’s oil&gas properties, including Eni’s share of the fixed assets of our joint ventures like Vår Energi AS, and including in the calculation the expected cash outflows committed to the Company’s forestry projects.

In October 2018 the Intergovernmental Panel on Climate Change (IPCC) stated, in a new report, that in order to limit global warming to 1.5°C, the world economy would need to undertake a deeper and complex transformation. We recognize that meeting this challenge in the next decades requires an even more rapid escalation, both in term of size and speed, of changes than were foreseen in the Paris Agreement. Currently, this scenario has yet to be complemented by a full set of pricing and other operating assumptions, which once available from the IPCC or other sources will be analyzed by the Company for the purpose of updating stress-testing models and methodologies.

Significant business and portfolio developments

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March 2020 – Signed 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 Naturgy, which comprise plans for restarting the Damietta liquefaction plant in Egypt by June 2020, the restructuring of the UFG joint-venture (Eni 50% and Naturgy 50%) and the settlement of all pending litigations with the Egyptian partners.

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March 2020 – Eni became an active member alongside BioCarbon Partners for the governance of the REDD+ Luangwa Community Forests Project in Zambia, with a commitment to purchase carbon credits for the next 20 years, until 2038.

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February 2020 – Third successful well with Agogo 3 in the Block 15/06 (Eni operator with a 36.84% interest) after the two wells 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.

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

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

•

January ~~2017: signed~~2020 – Made a ~~Memorandum of Understanding~~gas and condensate discovery with the Nigerian Authorities for the development of the mineral potential of the Country. The agreement also comprises the upgrading of the Port Harcourt refinery and a capacity doubling of the power generation unit in Okpai IPP.

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~~November 2016: signed four agreements in Bahrein with the National Oil Companies for the evaluation of the mineral potential of certain exploration areas and for the study of the Awali fields.~~

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October 2016: signed a binding agreement between the partners of the Area 4 in Mozambique (Eni East Africa, joint operation between Eni and CNPC, Galp, Kogas and ENH) and BP for the sale, over a 20-year period, of approximately 3.3 million tons of LNG per annum (corresponding to about 5 BCM), which will be produced at the Coral South Floating facility. The agreement, approved by the Government of Mozambique, is a fundamental step towards achieving the Final Investment Decision (FID) of the project. The achievement of the FID is prerequisite to the efficacy of the sale contract. Back in February 2016, the Mozambique authorities approved the first development phase of Coral, targeting production of 5 trillion cubic feet (TCF) of gas.

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October 2016: restarted production at the Kashagan field with the completion of works to fully replace the damaged pipelines following the gas leak occurred at the end of 2013. The production of 180 KBOE/d was achieved by year-end. The production capacity of 370 KBBL/d planned for the Phase 1 is expected to be achieved during 2017, when gas reinjection comes online.

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~~September 2016: as part of Eni’s “near-field” exploration strategy, activities resumed onshore Tunisia with the Larich East discovery. The~~Mahani-1 well ~~has been put into production by linking the discovery well to the MLD oil treatment center.~~

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September 2016: reached a production plateau of 700 mmCF/d (corresponding to 128 KBOE/d, 67 KBOE/d net to Eni) from the Nooros field. This record-setting production level was reached in just 13 months after the discovery and ahead of schedule, thanks to the success of the latest exploration wells drilled in the Nooros area and the drilling of new development wells. In addition, thanks to the mature operating environment and the conventional nature of the project, production costs are among the lowest in Eni’s portfolio.

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~~September 2016: the potential at the Baltim South West field discovery,~~concession Area B, in the ~~conventional water~~Emirate of ~~Egypt, was upped due to successful test of the first appraisal well. The discovery is located near the Nooros field.~~

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September 2016: successfully drilled the Zohr 5x appraisal well, located in 1,538 meters of water depth and 12 kilometers south west from the discovery well. The appraisal well confirmed the overall potential of the Zohr Field. The Zohr development was sanctioned by Egyptian authorities in February 2016. Expected the drilling of a sixth well that will accelerate the production start-up within the end of 2017.

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March 2016: production start-up at the Goliat oilfield, which is the first producing oilfield in the Barents Sea in the license PL229. Goliat is operated through floating cylindrical production and storage vessel (FPSO). Production has achieved the full-field plateau at 100 KBBL/d (65 KBBL/d net to Eni)Sharjah (UAE).

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~~In 2016, Eni increased its exploration rights portfolio by about 10,500 square kilometers net, mainly~~January 2020 – Awarded the operatorship with a 60% interest in ~~Egypt, Ghana, Morocco, Montenegro, Norway and~~ the ~~United Kingdom.~~Block 28, offshore Angola.

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~~As part~~January 2020 – Awarded 17 new exploration licenses to Vår Energi in Norway, with 7 operatorships.

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December 2019 – Signed an agreement with Falck Renewables for the joint development of ~~its strategy designed to evolve the Company’s business model towards a low-carbon environment, Eni intends to develop~~ renewable energy projects in ~~its countries~~the United States to develop at least 1 GW of ~~operations. In 2016,~~installed capacity by the end of 2023.

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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.

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

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December 2019 – Closed the disposal of a ~~large scale in Italy and abroad: (i) The “Italy project” plans~~20% interest to ~~build facilities, mainly~~Neptune in the ~~solar~~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.

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December 2019 – Awarded a 50 MWp photovoltaic business, in owned industrial areas, which are ready to use and currently lack any industrial value. Fifteen projects have been identified with an overall capacity of approximately 220 MW to be installed by 2022. The first phase of the project foresees the installation of five units: Assemini and Porto Torres in Sardinia (obtained the Final Investment Decision for both projects, while the approval is ongoing from the relevant authorities), Monte Sant’Angelo in Puglia and Priolo in Sicily (FID obtained) and finally Augusta in Sicily; (ii) Outside Italy the company has identified a number of projects to be deployed in countries of operations considered strategic for the Company (mainly Africa and Asia) to increase Eni’s energy efficiency, the sustainability of our consumptions, as well as to improve the access to energy of local communities through a more sustainable energy mix. In December 2016 Eni obtained the FID for a development project in the ~~upstream field BRN in Algeria. Furthermore,~~southern Kazakhstan, as a ~~number~~result of ~~agreements for collaboration have been settled with Ghana, Algeria and Tunisia, to strengthen Eni’s presence in these countries and to enlarge~~an auction managed by the Kazakh Authorities.

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~~scope of activities. Finally, in 2016 Eni signed strategic framework agreements with: (i) General Electric (GE)~~•

October 2019 – Signed an agreement with Italian public and private authorities, Cassa Depositi e Prestiti (CDP), Fincantieri and Terna to set up a joint venture for the development and installation of ~~innovative technologies~~power plants feed with wave-energy.

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October 2019 – Made a new near-field oil 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.

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October 2019 – Started production at the Obiafu 41 gas and condensate discovery, which was made in August 2019, in the OML 61 concession, in the Niger Delta, just 3 weeks after well completion.

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

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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.

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

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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.

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September 2019 – Started production at the Baltim South West gas project in the Great Nooros Area, in Egypt, in just nineteen months after the FID.

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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).

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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).

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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.

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

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

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

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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.

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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.

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

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

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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.

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

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

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May 2019 – Acquired a 10% stake in three blocks, A5-B, Z5-C and ~~greenfield)~~Z5-D in Mozambique, located in the deep waters of Angoche and ~~hybrid renewable projects~~Zambesi Basins.

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

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

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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 S.p.A., a company focused on ~~energy efficiency. This~~post-consumer plastic recovery and recycling technologies, an agreement ~~is intended~~ to ~~identify~~develop a new range of plastic products made from recycled packaging.

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May 2019 – Made a gas and ~~develop jointly projects for power generation from renewable sources on large scale; (ii) Terna, Italian grid~~condensate discovery in CTP-Block 4 (Eni operator ~~for electricity transmission, for the evaluation of opportunities for the development of energy systems~~ with a ~~focus~~42.47% interest) in the Akoma exploration prospect, offshore Ghana.

•

May 2019 – Signed an Exploration and Production Sharing Agreement (EPSA) with the National Oil and Gas Authority of the Kingdom of Bahrain (NOGA) for Block 1, offshore Bahrain.

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April 2019 – Finalized the acquisition of an offshore exploration concession in the Emirate of Ras al Khaimah, awarded the operatorship with a 90% share in the Area A.

For significant business and portfolio developments occurred from January 2019 to March 2019 see also the Annual Report on ~~sustainability and supporting production from renewables.~~Form 20-F 2018 filed to SEC on April 5, 2019.

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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 LNG operations, in 4441 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Australia, ~~Venezuela,~~ Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and ~~Mozambique.~~the United Arab Emirates. In ~~2016,~~2019, Eni average daily production amounted to ~~1,671~~1,736 KBOE/d on an available-for-sale basis. As of December 31, ~~2016,~~2019, Eni’s total proved reserves amounted to ~~7,490~~7,268 mmBOE; proved reserves of subsidiaries totaled ~~6,613~~6,287 mmBOE; Eni’s share of reserves of equity-accounted entities ~~stood to 877~~was 981 mmBOE.

“Eni’s strategy and short-to-medium term targets in its Exploration & Production operations is to pursue profitable production growth by developing its portfolio of projects underway and by optimizing its current producing fields. We plan to achieve a production growth rate of 3% on average post disposals in the next 2017-2020 four-year period. Our production plans are incorporating our Brent price scenario of 55$/BBL in 2017 and a gradual recovery in the subsequent years up to our long-term case of 70$/BBL in 2020 and going forwards (on constant monetary term compared to 2020, i.e. from 2021 onwards crude oil prices will grow in line with a projected inflationary rate); as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices whichsegment are disclosed ~~under “Item~~in Item 5 – Management’s expectations of ~~operations”~~

Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations including, North Africa, Sub-Saharan Africa and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. New field start-ups, production ramp-ups and continuing production optimization will add approximately 850 KBOE/d in 2020; over 60% of these new projects have already been sanctioned and Eni is operator in approximately 70%.

Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion and reducing facilities downtime. This will require intense development activities of work-over and infilling and careful planning of maintenance activities. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery.

Management plans to invest some €27.1 billion to explore for and to develop reserves over the next four years, with a decrease of 13% net of exchange rate effects versus the previous four-year plan to mitigate the impact of a low oil price environment and net of planned disposal. We plan to prioritize lower intensity projects, brown-field developments and infilling wells mainly in Egypt, Libya and Algeria, while we plan to re-schedule spending in some large projects. This re-scheduling will account for half of the overall reduction, while the remaining will be determined by contracts renegotiations.

Planned expenditures in exploration are expected to be some €2.1 billion, slightly lower than the previous four-year plan. Exploration expenditure will be focused on proven plays, near field and appraisal exploration, where we plan to drill 50% of our scheduled wells in 2017-2018. Management planned to progressively increase activity in high-risk high-rewards targets, retaining large stakes in those initiatives with a view of implementing Eni’s dual exploration model.

Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight control on project time schedules and costs and reducing the time span, which is necessary to develop and market reserves. We plan to achieve efficient development of our reserves by: (i) in-sourcing critical engineering and project management activities also redeploying to other areas key competences, which will be freed with the start-up of certain strategic projects and increase direct control and governance on construction and commissioning activities; and (ii) signing framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows. Based on those initiatives, we believe that almost all of our projects which we are currently developing over the next four years will be completed on time and on budget.

Finally we plan to achieve further cost efficiencies by: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale;

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(ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; (iii) applying our technologies which we believe can reduce drilling and completion costs; and (iv) renegotiating contracts for oilfield services and other items to reap the benefits of the deflationary trend in the industry.

We plan to mitigate the operational risk relating to drilling activities by applying Eni’s rigorous procedures throughout the engineering and execution stages, by leveraging on proprietary drilling technologies, excellent skills and know-how, increased control of operations and by deploying technologies which we believe to be able to reduce blow-out risks and to enable the Company to respond quickly and effectively in case of emergencies.

~~For the year 2017, management plans to spend over €6 billion in reserves development and exploration projects, net of planned disposals.~~operations.”

Disclosure of reserves

Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the ~~first-day-of-the-month~~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 to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. 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 ~~buy-back and~~ 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 ~~entrusted with the task~~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.

TABLE OF CONTENTS

Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which ~~has~~ stated that those guidelines comply with the SEC rules~~(1)~~1. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines.

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department and the operations unit at the head office ~~verifies~~verify the production profiles of such properties where significant changes have ~~occurred;~~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~~above-mentioned units and aggregates worldwide reserves data.

The head of the Reserves Department attended the “Università degli Studi di Milano” and received a Master of Science degree in Physics in 1988. He has more than 2530 years of experience in the oil&gas industry and more than 1520 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested by the role and ~~maintains~~complies with the ~~highest~~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

~~Since 1991,~~ Eni has ~~requested qualified~~its proved reserves audited on a rotational basis by independent oil engineering companies ~~to carry out an independent evaluation(2)~~2 ~~of part of its proved reserves on a rotational basis.~~. The description of qualifications of the persons primarily responsible for the reserves audit is included in the ~~third party~~third-party audit report~~(3)~~3. 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 ~~economic~~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~~third-party evaluators. In ~~2016,~~2019, Ryder Scott Company and DeGolyer and MacNaughton ~~and Gaffney, Cline & Associates~~ provided an independent evaluation of approximately ~~41%~~31% of Eni’s total proved reserves at December 31, ~~2016~~2019~~(4)~~4, confirming, as in previous years, the reasonableness of Eni internal evaluation~~(5)~~5.

In the ~~2014-2016~~2017-2019 three-year period, ~~94%~~86% of Eni total proved reserves were subject to an independent evaluation. As at December 31, ~~2016,~~2019, the Zohr field in Egypt was the main Eni ~~properties,~~property, which did not undergo an independent evaluation in the last three ~~years, were Zubair (Iraq), Bu Attifel (Libya) and CAFC-MLE (Algeria).~~years. Management expects that the Zohr field will be subject to an independent evaluation in 2020.

~~(1)~~1

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

~~(2)~~2

From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder ~~Scott and from 2015,~~Scott. In 2018, the Societé Generale de Surveillance (SGS) company also ~~Gaffney, Cline & Associates.~~provided an independent certification.

~~(3)~~3

See “Item 19 – Exhibits”.

~~(4)~~4

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

~~(5)~~5

See “Item 19 – Exhibits”.

TABLE OF CONTENTS

Summary of proved oil and gas reserves

The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, ~~2016, 2015~~2019, 2018 and ~~2014. Net proved reserves are set out in more detail under the heading “Supplemental oil and gas information” on page F-147.~~

~~HYDROCARBONS~~
~~(mmBOE)~~2017.

HYDROCARBONS (mmBOE)	Italy	Rest of Europe	North Africa	~~of which~~ Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total reserves
Consolidated subsidiaries1
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
Dec. 31, 2017	422	525	1,052	1,078	1,436	1,150	427	203	137	6,430
developed	350	360	532	463	856	891	238	176	101	3,967
undeveloped	72	165	520	615	580	259	189	27	36	2,463
Equity-accounted entities2
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
Dec. 31, 2017			14		75		1	470		560
developed			14		20		1	359		394
undeveloped					55			111		166
Consolidated subsidiaries and equity accounted entities
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
Dec. 31, 2017	422	525	1,066	1,078	1,511	1,150	428	673	137	6,990
developed	350	360	546	463	876	891	239	535	101	4,361
undeveloped	72	165	520	615	635	259	189	138	36	2,629

(1)

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

(2)

Reserves volumes of the Rest of Europe area, in 2018, are affected by the merger agreement that provided for the sale of the reserves of the former subsidiary Eni Norge as part of the business combination with Point Resources and the acquisition of Eni’s share of the reserves held by the combined company Vår Energi, an equity-accounted entity participated by Eni with a 69.6% interest.

TABLE OF CONTENTS

LIQUIDS
(mmBBL)

Italy

Rest
of
Europe

North
Africa

Egypt

Sub-
Saharan
Africa

Kazakhstan

Rest
of
Asia

Americas

Australia
and
Oceania

Total
reserves

Consolidated subsidiaries

~~Year ended Dec. 31, 2014~~

~~503~~

~~544~~

~~1,740~~

~~1,239~~

~~1,069~~

~~285~~

~~232~~

~~160~~

~~5,772~~

~~developed~~

~~401~~

~~335~~

~~904~~

~~702~~

~~589~~

~~112~~

~~188~~

~~135~~

~~3,366~~

~~undeveloped~~

~~102~~

~~209~~

~~836~~

~~537~~

~~480~~

~~173~~

~~44~~

~~25~~

~~2,406~~

~~Year ended Dec. 31, 2015~~

~~465~~

~~495~~

~~1,694~~

~~1,282~~

~~1,198~~

~~422~~

~~269~~

~~150~~

~~5,975~~

~~developed~~

~~362~~

~~404~~

~~1,010~~

~~764~~

~~689~~

~~159~~

~~217~~

~~115~~

~~3,720~~

~~undeveloped~~

~~103~~

~~91~~

~~684~~

~~518~~

~~509~~

~~263~~

~~52~~

~~35~~

~~2,255~~

~~Year ended Dec. 31, 2016~~

~~354~~

~~426~~

~~2,432~~

~~1,293~~

~~1,317~~

~~1,221~~

~~491~~

~~227~~

~~145~~

~~6,613~~

~~developed~~

~~287~~

~~374~~

~~957~~

~~352~~

~~809~~

~~966~~

~~175~~

~~205~~

~~111~~

~~3,884~~

~~undeveloped~~

~~67~~

~~52~~

~~1,475~~

~~941~~

~~508~~

~~255~~

~~316~~

~~22~~

~~34~~

~~2,729~~

~~Equity-accounted entities~~

~~Year ended Dec. 31, 2014~~

~~16~~

~~81~~

~~728~~

~~830~~

~~developed~~

~~15~~

~~23~~

~~26~~

~~67~~

~~undeveloped~~

~~58~~

~~702~~

~~763~~

~~Year ended Dec. 31, 2015~~

~~14~~

~~87~~

~~810~~

~~915~~

~~developed~~

~~14~~

~~22~~

~~265~~

~~303~~

~~undeveloped~~

~~65~~

Dec. 31, 2019

194

468

264

694

746

491

225

3,124

developed

137

301

149

519

682

245

148

2,219

undeveloped

167

115

175

246

2905

Dec. 31, 2018

~~545~~208

493

279

718

704

476

252

3,183

developed

156

317

153

551

587

252

143

2,208

undeveloped

176

126

167

117

224

109

~~612~~975

~~Year ended~~ Dec. 31, ~~2016~~2017

215

360

~~14~~476

280

~~82~~764

766

232

162

3,262

developed

169

219

306

203

546

547

144

2,220

undeveloped

141

170

218

219

151

~~779~~

~~877~~1,042

~~developed~~

~~14~~

~~26~~

~~349~~

~~391~~

~~undeveloped~~Equity-accounted entities1

~~56~~

~~430~~

~~486~~

~~Consolidated subsidiaries~~
~~and equity accounted entities~~

~~Year ended~~ Dec. 31, ~~2014~~

~~503~~

~~544~~

~~1,756~~2019

~~1,320~~424

~~1,069~~

~~290~~

~~960~~

~~160~~

~~6,602~~

~~developed~~

~~401~~

~~335~~

~~919~~12

~~725~~

~~589~~

~~115~~

~~214~~

~~135~~

~~3,433~~

~~undeveloped~~

~~102~~

~~209~~

~~837~~

~~595~~

~~480~~

~~175~~

~~746~~

~~25~~

~~3,169~~

~~Year ended Dec. 31, 2015~~

~~465~~

~~495~~

~~1,708~~

~~1,369~~

~~1,198~~

~~426~~

~~1,079~~

~~150~~

~~6,890~~

~~developed~~

~~362~~

~~404~~

~~1,024~~

~~786~~

~~689~~

~~161~~

~~482~~

~~115~~

~~4,023~~

~~undeveloped~~

~~103~~

~~91~~

~~684~~

~~583~~

~~509~~

~~265~~

~~597~~

~~35~~

~~2,867~~

~~Year ended Dec. 31, 2016~~

~~354~~

~~426~~

~~2,446~~

~~1,293~~

~~1,399~~

~~1,221~~

~~493~~

~~1,006~~

~~145~~

~~7,490~~

~~developed~~

~~287~~

~~374~~

~~971~~

~~352~~

~~835~~

~~966~~

~~177~~

~~554~~

~~111~~

~~4,275~~

~~undeveloped~~

~~67~~

~~52~~

~~1,475~~

~~941~~

~~564~~

~~255~~

~~316~~

~~452~~

~~34~~

~~3,215~~

~~TABLE OF CONTENTS~~

~~LIQUIDS~~
~~(mmBBL)~~

~~Italy~~

~~Rest~~
of
~~Europe~~

~~North~~
~~Africa~~

~~of which~~
~~Egypt~~

~~Sub-~~
~~Saharan~~
~~Africa~~

~~Kazakhstan~~

~~Rest of~~
~~Asia~~

~~Americas~~

~~Australia~~
~~and~~
~~Oceania~~

~~Total~~
~~reserves~~

~~Consolidated subsidiaries~~10

~~Year ended Dec. 31, 2014~~

~~243~~

~~331~~

~~776~~31

~~739~~

~~697~~

~~131~~

~~147~~

~~13~~

~~3,077~~

~~developed~~

~~184~~

~~174~~

~~521~~

~~470~~

~~306~~

~~64~~

~~116~~

~~12~~

~~1,847~~

~~undeveloped~~

~~59~~

~~157~~

~~255~~

~~269~~

~~391~~

~~67~~

~~31~~

~~1,230~~

~~Year ended Dec. 31, 2015~~

~~228~~

~~305~~

~~821~~

~~787~~

~~771~~

~~262~~

~~189~~

~~3,372~~

~~developed~~

~~171~~

~~237~~

~~542~~

~~511~~

~~355~~

~~126~~

~~149~~

~~2,100~~

~~undeveloped~~

~~57~~

~~68~~

~~279~~

~~276~~

~~416~~

~~136~~

~~40~~

~~1,272~~

~~Year ended Dec. 31, 2016~~

~~176~~

~~264~~

~~735~~

~~281~~

~~809~~

~~767~~

~~307~~

~~163~~

~~3,230~~

~~developed~~

~~132~~

~~228~~

~~492~~

~~205~~

~~507~~

~~556~~

~~124~~

~~143~~

~~2,190~~

~~undeveloped~~

~~44~~

~~36~~

~~243~~

~~76~~

~~302~~

~~211~~

~~183~~

~~20~~

~~1,040~~

~~Equity-accounted entities~~

~~Year ended Dec. 31, 2014~~

~~14~~

~~17~~

~~117~~

~~149~~477

developed

219

~~13~~12

~~26~~31

~~46~~269

undeveloped

205

~~10~~

~~91~~

~~103~~

~~Year ended Dec. 31, 2015~~3

~~13~~

~~16~~208

Dec. 31, 2018

297

~~158~~37

~~187~~357

developed

154

205

undeveloped

143

152

Dec. 31, 2017

136

160

developed

~~13~~12

~~29~~

~~48~~

~~undeveloped~~

~~10~~

~~129~~

~~139~~

~~Year ended Dec. 31, 2016~~

~~13~~

~~15~~

~~140~~

~~168~~

~~developed~~

~~13~~

~~22~~25

undeveloped

~~118~~111

~~125~~117

Consolidated subsidiaries and equity accounted entities

~~Year ended Dec. 31, 2014~~

~~243~~

~~331~~

~~790~~

~~756~~

~~697~~

~~132~~

Dec. 31, 2019

194

465

480

264

~~13~~704

~~3,226~~

~~developed~~746

~~184~~

~~174~~

~~534~~

~~477~~

~~306~~

~~64~~

~~142~~

~~12~~

~~1,893~~

~~undeveloped~~

~~59~~

~~157~~491

256

~~279~~3,601

developed

~~391~~137

~~68~~256

~~122~~313

149

526

682

245

179

~~1,333~~

~~Year ended Dec. 31, 2015~~

~~228~~

~~305~~

~~834~~

~~803~~

~~771~~

~~262~~

~~347~~

~~3,559~~

~~developed~~

~~171~~

~~237~~

~~555~~

~~517~~

~~355~~

~~126~~

~~178~~

~~2,148~~2,488

undeveloped

~~68~~209

167

115

178

246

1,113

Dec. 31, 2018

208

345

504

279

730

704

476

289

3,540

developed

156

198

328

153

559

587

252

175

2,413

undeveloped

147

176

126

171

117

224

114

~~286~~

1,127

Dec. 31, 2017

~~416~~215

~~136~~360

488

280

776

766

232

298

3,422

developed

169

219

~~1,411~~

~~Year ended Dec. 31, 2016~~318

~~176~~203

~~264~~552

~~748~~547

~~281~~81

~~824~~169

~~767~~5

~~307~~

~~303~~

~~3,398~~

~~developed~~

~~132~~

~~228~~

~~505~~

~~205~~

~~515~~

~~556~~

~~124~~

~~165~~

~~2,233~~2,263

undeveloped

~~44~~46

~~36~~141

~~243~~170

~~76~~77

~~309~~224

~~211~~219

~~183~~151

~~138~~129

~~1,165~~1,159

(1)

TABLE OF CONTENTS

NATURAL GAS
(BCF)

Italy

Rest
of
Europe

North
Africa

~~of which~~
Egypt

Sub-
Saharan
Africa

Kazakhstan

Rest
of
Asia

Americas

Australia
and
Oceania

Total
reserves

Consolidated subsidiaries1

~~Year ended~~ Dec. 31, ~~2014~~2019

~~1,432~~752

~~1,171~~262

~~5,291~~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

1,364

414

2,245

~~2,744~~664

~~2,049~~54

~~846~~185

~~468~~5,041

Dec. 31, 2018

~~807~~1,199

~~14,808~~320

2,890

5,275

3,506

1,989

1,217

277

651

17,324

developed

~~1,192~~980

~~887~~300

~~2,110~~1,447

3,331

1,871

1,846

822

154

452

11,203

undeveloped

219

1,443

1,944

1,635

143

395

123

199

6,121

Dec. 31, 2017

1,131

896

3,145

4,351

3,660

2,108

1,065

225

709

17,290

developed

987

771

1,233

1,421

1,693

1,878

862

171

519

9,535

undeveloped

144

125

1,912

2,930

1,967

230

203

190

7,755

Equity-accounted entities2

~~1,271~~

~~1,553~~

~~261~~

~~393~~

~~675~~

~~8,342~~

~~undeveloped~~

~~240~~

~~284~~

~~3,181~~

~~1,473~~

~~496~~

~~585~~

~~75~~

~~132~~

~~6,466~~

~~Year ended Dec. 31, 2015~~

~~1,304~~

~~1,044~~

~~4,798~~

~~2,714~~

~~2,354~~

~~878~~

~~439~~

~~771~~

~~14,302~~

~~developed~~

~~1,051~~

~~919~~

~~2,566~~

~~1,390~~

~~1,830~~

~~185~~

~~373~~

~~585~~

~~8,899~~

~~undeveloped~~

~~253~~

~~125~~

~~2,232~~

~~1,324~~

~~524~~

~~693~~

~~66~~

~~186~~

~~5,403~~

~~Year ended Dec. 31, 2016~~

~~977~~

~~878~~

~~9,258~~

~~5,520~~

~~2,767~~

~~2,485~~

~~1,003~~

~~353~~

~~741~~

~~18,462~~

~~developed~~

~~845~~

~~801~~

~~2,531~~

~~799~~

~~1,651~~

~~2,239~~

~~280~~

~~338~~

~~559~~

~~9,244~~

~~undeveloped~~

~~132~~

~~77~~

~~6,727~~

~~4,721~~

~~1,116~~

~~246~~

~~723~~

~~15~~

~~182~~

~~9,218~~

~~Equity-accounted entities~~

~~Year ended~~ Dec. 31, ~~2014~~2019

772

287

~~15~~1,648

~~351~~2,721

developed

~~18~~597

~~3,353~~14

~~3,737~~88

1,648

2,347

undeveloped

175

199

374

Dec. 31, 2018

360

310

1,716

2,400

developed

276

1,716

2,063

undeveloped

253

337

Dec. 31, 2017

349

1,819

2,182

developed

~~15~~14

~~89~~83

~~10~~

61,819

~~120~~1,916

undeveloped

~~262~~

~~3,347~~

~~3,617~~

~~Year ended Dec. 31, 2015~~

~~13~~

~~387~~

~~12~~

~~3,581~~

~~3,993~~

~~developed~~

~~13~~

~~85~~

~~1,295~~

~~1,402~~

~~undeveloped~~266

~~302~~

~~2,286~~

~~2,591~~

~~Year ended Dec. 31, 2016~~

~~15~~

~~368~~

~~3,484~~

~~3,871~~

~~developed~~

~~15~~

~~104~~

~~1,782~~

~~1,905~~

~~undeveloped~~

~~264~~

~~1,702~~

~~1,966~~266

Consolidated subsidiaries and equity accounted entities

~~Year ended Dec. 31, 2014~~

~~1,432~~

~~1,171~~

~~5,306~~

~~3,095~~

~~2,049~~

~~864~~

~~3,821~~

~~807~~

~~18,545~~

~~developed~~

~~1,192~~

~~887~~

~~2,125~~

~~1,360~~

~~1,553~~

~~271~~

~~399~~

~~675~~

~~8,462~~

~~undeveloped~~

~~240~~

~~284~~

~~3,181~~

~~1,735~~

Dec. 31, 2019

~~496~~752

~~593~~1,034

~~3,422~~2,752

~~132~~5,191

~~10,083~~

~~Year ended Dec. 31, 2015~~4,390

~~1,304~~1,969

~~1,044~~1,349

~~4,811~~1,888

507

19,832

developed

657

839

1,388

4,777

1,946

1,969

685

1,834

322

14,417

undeveloped

195

1,364

414

2,444

~~3,101~~664

~~2,354~~54

~~890~~185

~~4,020~~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

Dec. 31, 2017

1,131

896

3,159

4,351

4,009

2,108

1,065

2,044

709

19,472

developed

987

771

~~18,295~~

~~developed~~1,247

~~1,051~~1,421

~~919~~1,776

~~2,579~~1,878

862

~~1,475~~1,990

~~1,830~~519

~~194~~

~~1,668~~

~~585~~

~~10,301~~11,451

undeveloped

~~253~~144

125

~~2,232~~1,912

2,930

~~1,626~~2,233

~~524~~230

~~696~~203

~~2,352~~54

~~186~~190

~~7,994~~8,021

~~Year ended Dec. 31, 2016~~

~~977~~

~~878~~

~~9,273~~

~~5,520~~

~~3,135~~

~~2,485~~

~~1,007~~

~~3,837~~

~~741~~

~~22,333~~

~~developed~~

~~845~~

~~801~~

~~2,546~~

~~799~~

~~1,755~~

~~2,239~~

~~284~~

~~2,120~~

~~559~~

~~11,149~~

~~undeveloped~~

~~132~~

~~77~~

~~6,727~~

~~4,721~~

~~1,380~~

~~246~~

~~723~~

~~1,717~~

~~182~~

~~11,184~~

(1)

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

(2)

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Proved reserves of natural gas liquids are immaterial to the Group operations.

Volumes of oil and natural gas applicable to ~~long-term~~long- term supply agreements with foreign governments in mineral assets where Eni is operator totaled ~~212~~128 mmBOE as of December 31, ~~2016 (139~~2019 (148 and ~~282~~178 mmBOE as of December 31, ~~2015~~2018 and ~~2014,~~2017, respectively). Said volumes are not included in reserves volumes shown in the table herein.

	Subsidiaries						Equity-accounted entities						Subsidiaries						Equity-accounted entities
	2014		2015		2016		2014		2015		2016
	(mmBOE)
Additions to proved reserves		643		849		1,254		11		98		(10)
(mmBOE)													2019		2018		2017		2019		2018		2017
Revisions of previous estimates														459		590		466		62		(99)		(285)
Improved recovery																13		20
Extensions and discoveries														101		169		483		6
Purchases of minerals-in-place		4												30		332		2		184		363
Sales of minerals-in-place		(8)		(17)
Production for the year (a)		(575)		(629)		(616)		(8)		(13)		(28)

Sales of minerals-in-place(a)														(42)		(528)		(523)		(6)		(1)
Total additions to proved reserves														548		576		448		246		263		(285)
Production for the year(b)														(617)		(650)		(631)		(62)		(26)		(32)

(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 ~~over~~compared to production sold of ~~608.6~~630.6 mmBOE ~~(549.5~~(622.3 mmboe in ~~2014~~2017 and ~~642.4~~625.0 mmboe in ~~2015)~~2018) reflected ~~natural gas~~hydrocarbons volumes of ~~32.1~~45.4 mmBOE consumed in operations ~~(29.4~~(35.2 mmBOE in ~~2014~~2017 and ~~26.4~~43.5 mmBOE in ~~2015)~~2018), changes in inventories and other factors.

Subsidiaries and
equity-accounted entities
2014 2015 2016
(%)
Proved reserves replacement ratio of
subsidiaries and equity-accounted entities, all
sources 112 145 193
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic 112 148 193

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

Eni’s proved reserves as of December 31, ~~2016~~2019 totaled ~~7,490~~7,268 mmBOE (liquids ~~3,398~~3,601 mmBBL; natural gas ~~22,333~~19,832 BCF). Eni’s proved reserves reported an increase of ~~600~~115 mmBOE, or ~~8.7%~~1.6%, from December 31, ~~2015.~~ 2018 due to progress made in the year in exploring for 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, as well as other minor assets in Norway; and (iv) sales of minerals-in-place of 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.

All sources additions to proved reserves booked in ~~2016~~2019 were ~~1,244~~794 mmBOE; of which ~~1,254~~548 mmBOE came from Eni’s subsidiaries, ~~and negative~~which include sales of reserves as part of a long-term supply agreement as discussed above, while 246 mmBOE from Eni’s ~~share of~~ equity-accounted entities.

Due to a ~~lowered~~decrease in oil and gas prices compared to the Brent reference price used in the reserve estimation process at ~~$42.8~~$62.7 per barrel in ~~2016~~2019 ($5471.4 per barrel in ~~2015)~~2018), our all sources additions ~~were adversely affected~~decreased by ~~a downward revision of 76~~58 mmBOE, due to ~~our having to remove certain~~the removal of volumes of reserves which have become uneconomical in that environment, which were partially offset by higher volume entitlements at our PSA contracts 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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The methods (or technologies) used in the Eni’s proved reserves assessment in ~~2016~~2019 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates.

The all sources reserves replacement ratio ~~achieved~~reported by Eni’s subsidiaries and equity-accounted entities was ~~193%~~117% in ~~2016 (145%~~2019 (124% in ~~2015~~2018 and ~~112%~~25% in ~~2014).The~~2017). The organic reserves replacement ratio was 92% in 2019 (100% in 2018 and 103% in 2017) which excluded sales and purchases of minerals-in-place.

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~~– Uncertainties in estimates of oil and natural gas reserves”.

The average reserves life index of Eni’s proved reserves was ~~11.6~~10.6 years as of December 31, ~~2016,~~2019, which included reserves of both subsidiaries and equity-accounted entities.

Eni’s subsidiaries

Eni’s subsidiaries added ~~1,254~~548 mmBOE of proved oil~~&gas~~ and gas reserves in ~~2016.~~2019 net of sales and purchase of minerals- in- place. This comprised ~~173~~236 mmBBL of liquids and ~~5,808~~1,525 BCF of natural gas. ~~Additions~~The breakdown of total additions to proved reserves ~~derived from:~~is the following: (i) extensions and discoveries were ~~887~~up by 101 mmBOE ~~with major increase booked in Egypt following~~mainly due to the final investment ~~decision~~decisions made for the projects of Dalma in the ~~Zohr gas project;~~offshore United Arab Emirates, Assa North in Nigeria and Agogo field in the offshore operated Block 15/06 in Angola; (ii) revisions of previous estimates were ~~365~~up by 459 mmBOE and mainly ~~reported~~derived from the upward revisions of certain gas fields in ~~Libya, Iraq~~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 ~~continuous development activities and field performances; and (iii) improved recovery were 2 mmBOE mainly reported in Algeria and Norway.~~the take-or-pay clause, as discussed above.

Eni’s share of equity-accounted entities

~~Additions in~~ Eni’s share of equity-accounted ~~entities’~~entities added 246 mmBOE of proved oil~~&gas were negative~~ and gas reserves in ~~2016~~2019 net of sale and ~~derived from downward~~purchase minerals-in-place. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates ~~reported~~were up by 62 mmBOE mainly due to the progress in ~~Americas.~~development activities at the Balder X field in Norway; (ii) extensions and discoveries were up by 6 mmBOE mainly due to the production start-up of the Trestakk field in Norway; (iii) the purchase of ExxonMobil producing and development assets in Norway, as described above; and (v) sales of minerals-in-place referred to the minor producing assets in Norway.

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Proved undeveloped reserves

Proved undeveloped reserves as of December 31, ~~2016~~2019 totaled ~~3,215~~2,114 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to ~~1,165~~1,113 mmBBL, mainly concentrated in ~~Africa.~~Africa and Asia. Proved

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undeveloped reserves of natural gas amounted to ~~11,184~~5,415 BCF, mainly located in ~~Africa and Americas.~~Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to ~~1,040~~905 mmBBL of liquids and ~~9,218~~5,041 BCF of natural gas.

~~In 2016,~~ The table below provide a summary of changes in total proved undeveloped reserves ~~increased~~for 2019.

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)
Proved undeveloped reserves as of December 31, 2019		2,114

In 2019, total proved undeveloped reserves decreased by ~~348~~195 mmBOE mainly due ~~to:~~to progress made in maturing PUDs to proved developed (655 mmBOE). Additions to PUDs for the year included: (i) extensions and discoveries (up by ~~873~~101 mmBOE)~~, in particular in Egypt~~ mainly due to the final investment ~~decision sanctioned~~decisions made for the ~~Zohr discovery;~~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 ~~121~~327 mmBOE) mainly reported in ~~Congo~~Nigeria due to the final investment decision made for an expansion project of the Bonny liquefaction plant and ~~Iraq;~~in Egypt due to the development activity of the Zohr project; (iii) ~~reclassification~~purchases (up by 44 mmBOE) mainly related to ~~proved developed reserves~~the Vår Energi acquisition in Norway as discussed above; and (iv) sales of minerals-in-place (down by ~~646~~12 mmBOE). related to minor assets in Norway and the Merakes discovery in Indonesia, as mentioned above.

During ~~2016,~~2019, Eni ~~converted 646~~matured 655 mmBOE of proved undeveloped reserves to proved developed reserves due to ~~the~~ progress ofin 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 ~~(Kazakhstan), Perla (Venezuela),~~in Kazakhstan, Litchendjili ~~(Congo), Zubair (Iraq)~~in Congo, Ngl Eleme in Nigeria and ~~Goliat (Norway).~~Area 1 in Mexico.

In ~~2016,~~2019, capital expenditure amounted to approximately ~~€7.5~~€6.8 billion ~~and was made~~ to progress the development of ~~proved undeveloped reserves.~~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 ~~complex nature~~complexity of ~~the~~ development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. OfThe 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 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. The proved undeveloped reserves that have ~~been reported~~remained undeveloped for five years or more ~~years,~~at the ~~largest are~~balance sheet date mainly related ~~to forthcoming development phases of~~to: (i) the ~~Kashagan project in Kazakhstan (approximately 0.2 BBOE) and certain assets in Venezuela (approximately 0.4 BBOE) and~~Zubair field in Iraq ~~(approximately 0.2~~(0.1 BBOE), ~~as well as~~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 ~~(approximately 0.5~~(0.3 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a ~~long-term~~long- term gas supply agreement currently in force. In order to secure ~~fulfilment~~fulfillment of the contractual delivery quantities, ~~in Libya,~~ Eni will implement phased production start-up from the relevant fields, which are expected to be put in production over the next several ~~years.~~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 ~~regarding~~about risks associated with oil~~&gas~~ and gas development projects).

Eni remains strongly committed to put these projects into production ~~over~~in the ~~next few~~coming years. The length of the development period ~~is a function of~~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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Delivery commitments

Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities.

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately ~~453~~555 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Ghana, Indonesia, Libya, Nigeria, Norway and Venezuela.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally ~~referenced~~indexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available mainly from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production is expected to account for approximately ~~86%~~91% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, ~~2016.~~2019.

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

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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 ~~2016,~~2019, oil and natural gas production available for sale averaged ~~1,671~~1,736 KBOE/d ~~(1,688~~(1,732 KBOE/d in ~~2015) decreased~~2018). Production for the year expressed in barrel-of-oil equivalent was calculated assuming a natural gas conversion factor which was updated to 5,408 CF of gas equaling 1 barrel of oil without restating the comparative periods (it was 5,458 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 was barely unchanged from 2018.

The full year period results were affected by ~~1.0%~~the divestment of Eni’s interest 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 to establish the equity- accounted joint venture Vår Energi, and the termination of the Intisar production contract in Libya from ~~2015,~~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 in Asia, in Venezuela due to the ~~production shutdown~~current situation in the ~~Val d’Agri profit center (See also – oil and gas properties – Italy described above)~~Country, as well as ~~planned facilities downtime,~~mature fields decline, mainly in ~~the United Kingdom,~~Italy and the mature fields declines. These negatives were partially offset by new field start-ups and the continuing ramp-up of production at fields started in 2015, mainly reported in Angola, Egypt, Kazakhstan, Norway and Venezuela as well as higher production in Iraq and the price effects reported in PSA contracts.Angola. New field start-ups and ramp-ups of production added an estimated ~~280~~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.

Liquids production ~~(878~~(890 KBBL/d) ~~decreased~~increased by 306 KBBL/d, or ~~3.3%, due to~~approximately 1% from the full year of 2018. Start- ups and ramp-ups of the period, mainly in Mexico, Libya and Ghana, and production ~~shutdown~~growth in the ~~Val d’Agri profit center, planned facilities downtime~~United Arab Emirates and ~~the~~Nigeria were partly offset by facility shutdowns, mainly in Congo, lower production in Venezuela and mature fields decline. ~~These negatives were partially offset by new fields start-up and production ramp-up in particular in Angola, Kazakhstan and Norway as well as higher production in Iraq.~~

Natural gas production ~~(4,329~~(4,576 mmCF/d) ~~reported an increase of 45~~decreased by 54 mmCF/d, or ~~1.1% from 2015. Higher~~approximately 1% compared to the full year of 2018. Lower production in Indonesia and Venezuela as well as mature fields decline were partly offset by production ramp-ups of the period, mainly in Egypt and ~~Venezuela were partially offset by planned facilities downtime~~Ghana, and the ~~decline~~growth in Nigeria.

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Sales volumes of ~~mature fields.~~

~~Oil~~oil and gas production sold ~~amounted to 608.6~~were 630.6 mmBOE. The ~~3.4~~3.2 mmBOE difference over production on ~~an available-for-sale~~available -for-sale basis ~~(612 mmBOE)~~(633.8 mmBOE in 2019) reflected mainly changes in ~~inventories~~inventory and other factors. Approximately ~~68%~~66% of liquids production sold ~~(320~~(325.4 mmBBL) was destined to Eni’s mid-downstream sectors. About ~~22%~~18% of natural gas production sold ~~(1,574~~(1,650 BCF) was destined to Eni’s Gas & Power segment.

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

~~2014 Production available for sale~~ ~~(a)~~

~~Italy~~

~~Rest~~
of
~~Europe~~

~~North~~
~~Africa~~

~~Sub-~~
~~Saharan~~
~~Africa~~

~~Kazakhstan~~

~~Rest of~~
~~Asia~~

~~Americas~~

~~Australia~~
~~and~~
~~Oceania~~

~~Hydrocarbons production~~

~~Eni consolidated subsidiaries~~

~~(KBOE/d)~~

~~171~~

~~184~~

~~528~~

~~305~~

~~85~~

~~87~~

~~112~~

~~25~~

~~1,497~~

~~(mmBOE)~~

~~63~~

~~67~~

~~193~~

~~111~~

~~31~~

~~41~~

~~546~~

~~Eni share of equity-accounted entities~~

~~(KBOE/d)~~

~~10~~

~~20~~

~~(mmBOE)~~

~~Liquids production~~

~~Eni consolidated subsidiaries~~

~~(KBBL/d)~~

~~73~~

~~93~~

~~249~~

~~230~~

~~52~~

~~36~~

~~74~~

~~813~~

~~(mmBBL)~~

~~27~~

~~34~~

~~91~~

~~84~~

~~19~~

~~13~~

~~27~~

~~297~~

~~Eni share of equity-accounted entities~~

~~(KBBL/d)~~

~~10~~

~~15~~

~~(mmBBL)~~

~~Natural gas production~~

~~Eni consolidated subsidiaries~~

~~(mmCF/d)~~

~~541~~

~~498~~

~~1,533~~

~~411~~

~~181~~

~~279~~

~~205~~

~~106~~

~~3,754~~

~~(BCF)~~

~~198~~

~~182~~

~~559~~

~~150~~

~~66~~

~~102~~

~~75~~

~~39~~

~~1,371~~

~~Eni share of equity-accounted entities~~

~~(mmCF/d)~~

~~18~~

~~28~~

~~(BCF)~~

~~10~~

Average daily production available for sale(a)(b)

	2019			2018			2017
	Liquids (KBBL/d)	Natural gas (mmCF/d)	Hydrocarbons (KBOE/d)	Liquids (KBBL/d)	Natural gas (mmCF/d)	Hydrocarbons (KBOE/d)	Liquids (KBBL/d)	Natural gas (mmCF/d)	Hydrocarbons (KBOE/d)
Eni consolidated subsidiaries
Italy	53	338	116	60	386	130	53	402	127
Rest of Europe	23	158	52	113	410	188	102	443	183
Croatia					10	2		16	3
Norway				89	225	131	81	250	126
United Kingdom	23	158	52	24	175	55	21	177	54
North Africa	166	1,023	356	154	1,188	372	158	1,632	457
Algeria	62	33	69	65	35	72	68	35	75
Libya	101	980	282	86	1,141	295	87	1,585	377
Tunisia	3	10	5	3	12	5	3	12	5
Egypt	75	1,425	338	77	1,147	287	72	784	216
Sub-Saharan Africa	247	415	324	244	346	308	247	328	305
Angola	101		101	111		111	119		119
Congo	59	93	77	65	104	84	63	68	74
Ghana	23	42	30	15	9	17	8		8
Nigeria	64	280	116	53	233	96	57	260	104
Kazakhstan	99	240	143	91	228	133	83	231	126
Rest of Asia	85	350	150	77	412	152	53	282	105
China	1		1	1		1	2		2
Indonesia	2	255	49	3	315	60	3	161	33
Iraq	26		26	28		28	40		40
Pakistan		92	17		97	18		121	22
Turkmenistan	7		7	6		6	8		8
United Arab Emirates	49	3	50	39		39
Americas	56	48	64	52	108	72	63	181	96
Ecuador	6		6	12		12	12		12
Mexico	4	2	4
Trinidad & Tobago					36	6		55	10
United States	46	46	54	40	72	54	51	126	74
Australia and Oceania	2	134	27	2	110	22	2	101	21
Australia	2	134	27	2	110	22	2	101	21
	806	4,131	1,570	870	4,335	1,664	833	4,384	1,636
Eni share of equity-accounted entities
Angola	4	86	20	3	75	17	3	72	17
Indonesia					2	1	1	9	2
Norway	74	168	105
Tunisia	3		3	3	2	3	3	2	3
Venezuela	3	191	38	8	216	47	12	267	61
	84	445	166	14	295	68	19	350	83
Total	890	4,576	1,736	884	4,630	1,732	852	4,734	1,719

(a)

It excludes production volumes of ~~natural gas~~hydrocarbons consumed in operations. Said volumes were ~~442 mmCF/~~124, 119 and 97 KBOE/d ~~or 29.4 mmBOE.~~in 2019, 2018 and 2017, respectively.

(b)

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

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~~2015 Production available for sale~~ ~~(a)~~

~~Italy~~

~~Rest~~
of
~~Europe~~

~~North~~
~~Africa~~

~~Sub-~~
~~Saharan~~
~~Africa~~

~~Kazakhstan~~

~~Rest of~~
~~Asia~~

~~Americas~~

~~Australia~~
~~and~~
~~Oceania~~

~~Hydrocarbons production~~

~~Eni consolidated subsidiaries~~

~~(KBOE/d)~~

~~161~~

~~179~~

~~631~~

~~324~~

~~92~~

~~123~~

~~120~~

~~25~~

~~1,655~~

~~(mmBOE)~~

~~59~~

~~65~~

~~230~~

~~119~~

~~33~~

~~45~~

~~44~~

~~604~~

~~Eni share of equity-accounted entities~~

~~(KBOE/d)~~

~~24~~

~~33~~

~~(mmBOE)~~

~~12~~

~~Liquids production~~

~~Eni consolidated subsidiaries~~

~~(KBBL/d)~~

~~69~~

~~85~~

~~268~~

~~256~~

~~56~~

~~77~~

~~75~~

~~891~~

~~(mmBBL)~~

~~25~~

~~31~~

~~98~~

~~93~~

~~20~~

~~28~~

~~325~~

~~Eni share of equity-accounted entities~~

~~(KBBL/d)~~

~~12~~

~~17~~

~~(mmBBL)~~

~~Natural gas production~~

~~Eni consolidated subsidiaries~~

~~(mmCF/d)~~

~~503~~

~~515~~

~~1,990~~

~~378~~

~~199~~

~~259~~

~~243~~

~~107~~

~~4,194~~

~~(BCF)~~

~~183~~

~~188~~

~~727~~

~~138~~

~~73~~

~~94~~

~~89~~

~~39~~

~~1,531~~

~~Eni share of equity-accounted entities~~

~~(mmCF/d)~~

~~19~~

~~68~~

~~90~~

~~(BCF)~~

Annual production available for sale(a)(b)

	2019			2018			2017
	Liquids (mmBBL)	Natural gas (BCF)	Hydrocarbons (mmBOE)	Liquids (mmBBL)	Natural gas (BCF)	Hydrocarbons (mmBOE)	Liquids (mmBBL)	Natural gas (BCF)	Hydrocarbons (mmBOE)
Eni consolidated subsidiaries
Italy	19	123	42	22	141	48	19	147	46
Rest of Europe	8	58	19	41	150	68	37	162	67
Croatia					4	1		6	1
Norway				33	82	47	29	91	46
United Kingdom	8	58	19	8	64	20	8	65	20
North Africa	61	374	130	56	434	136	58	596	167
Algeria	23	12	25	24	13	26	25	13	27
Libya	37	358	103	31	417	108	32	579	138
Tunisia	1	4	2	1	4	2	1	4	2
Egypt	27	520	123	28	419	105	26	286	79
Sub-Saharan Africa	90	152	118	89	126	112	90	119	111
Angola	37		37	41		41	43		43
Congo	22	34	28	24	38	30	23	24	27
Ghana	8	16	11	5	3	6	3		3
Nigeria	23	102	42	19	85	35	21	95	38
Kazakhstan	36	87	52	34	83	49	30	84	46
Rest of Asia	32	127	56	28	150	55	20	103	38
China	1		1	1		1	1		1
Indonesia		93	18	1	115	22	1	59	11
Iraq	10		10	10		10	15		15
Pakistan		33	6		35	6		44	8
Turkmenistan	3		3	2		2	3		3
United Arab Emirates	18	1	18	14		14
Americas	20	18	23	19	40	26	23	66	35
Ecuador	2		2	4		4	4		4
Mexico	1	1	1
Trinidad & Tobago					13	2		20	4
United States	17	17	20	15	27	20	19	46	27
Australia and Oceania	1	49	10	1	40	8	1	37	8
Australia	1	49	10	1	40	8	1	37	8
	294	1,508	573	318	1,583	607	304	1,600	597
Eni share of equity-accounted entities
Angola	2	31	7	1	27	6	1	27	6
Indonesia							1	3	1
Norway	27	61	39
Tunisia	1		1	1	1	1	1	1	1
Venezuela	1	70	14	3	79	18	4	97	22
	31	162	61	5	107	25	7	128	30
Total	325	1,670	634	323	1,690	632	311	1,728	627

(a)

It excludes production volumes of ~~natural gas~~hydrocarbons consumed in operations. Said volumes were ~~397 mmCF/d or 26.4 mmBOE.~~45.4, 43.5 and 35.2 mmBOE in 2019, 2018 and 2017, respectively.

~~2016 Production available for sale~~ ~~(a)~~

(b)

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

~~Italy~~

~~Rest~~
of
~~Europe~~

~~North~~
~~Africa~~

~~Sub-~~
~~Saharan~~
~~Africa~~

~~Kazakhstan~~

~~Rest of~~
~~Asia~~

~~Americas~~

~~Australia~~
~~and~~
~~Oceania~~

~~Hydrocarbons production~~

~~Eni consolidated subsidiaries~~

~~(KBOE/d)~~

~~127~~

~~195~~

~~608~~

~~312~~

~~107~~

~~114~~

~~23~~

~~1,600~~

~~(mmBOE)~~

~~47~~

~~71~~

~~222~~

~~114~~

~~39~~

~~42~~

~~585~~

~~Eni share of equity-accounted entities~~

~~(KBOE/d)~~

~~60~~

~~71~~

~~(mmBOE)~~

~~22~~

~~27~~

~~Liquids production~~

~~Eni consolidated subsidiaries~~

~~(KBBL/d)~~

~~47~~

~~109~~

~~241~~

~~247~~

~~65~~

~~78~~

~~69~~

~~859~~

~~(mmBBL)~~

~~17~~

~~40~~

~~88~~

~~91~~

~~24~~

~~28~~

~~25~~

~~314~~

~~Eni share of equity-accounted entities~~

~~(KBBL/d)~~

~~14~~

~~19~~

~~(mmBBL)~~

~~Natural gas production~~

~~Eni consolidated subsidiaries~~

~~(mmCF/d)~~

~~436~~

~~468~~

~~2,000~~

~~353~~

~~234~~

~~199~~

~~243~~

~~110~~

~~4,043~~

~~(BCF)~~

~~159~~

~~171~~

~~732~~

~~129~~

~~86~~

~~73~~

~~89~~

~~40~~

~~1,479~~

~~Eni share of equity-accounted entities~~

~~(mmCF/d)~~

~~16~~

~~15~~

~~252~~

~~286~~

~~(BCF)~~

~~105~~

~~(a)~~

~~It excludes production volumes of natural gas consumed in operations. Said volumes were 478 mmCF/d or 32.1 mmBOE.~~

TABLE OF CONTENTS

Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 5671 KBOE/d, 8454 KBOE/d and 7855 KBOE/d in ~~2016, 2015~~2019, 2018 and ~~2014,~~2017, respectively.

The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. ~~Also~~In addition, Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided. ~~The average~~

Average sales prices and production cost ~~does not include any ad valorem or severance taxes.~~

~~TABLE OF CONTENTS~~

~~AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION~~per unit of production

($)	Italy	Rest of Europe	North Africa	~~of which~~ Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
~~2014~~2017
~~Consolidated subsidiaries~~
~~Oil and condensates, per BBL~~	~~87.80~~	~~88.80~~	~~88.99~~		~~93.45~~	~~91.86~~	~~77.99~~	~~79.13~~	~~91.61~~	~~88.90~~
~~Natural gas, per KCF~~	~~8.74~~	~~8.49~~	~~8.08~~		~~2.12~~	~~0.62~~	~~6.18~~	~~3.96~~	~~7.46~~	~~6.83~~
~~Average production cost, per BOE~~	~~15.19~~	~~13.61~~	~~6.79~~		~~18.88~~	~~8.94~~	~~10.70~~	~~11.75~~	~~20.14~~	~~12.00~~
~~Equity-accounted entities~~
~~Oil and condensates, per BBL~~			~~17.94~~				~~65.90~~	~~81.48~~		~~70.56~~
~~Natural gas, per KCF~~			~~6.08~~				~~15.64~~			~~14.13~~
~~Average production cost, per BOE~~			~~12.50~~				~~9.79~~	~~42.27~~		~~26.18~~
~~2015~~
Consolidated subsidiaries
Oil and condensates, per BBL	~~43.46~~46.51	~~45.88~~47.81	~~46.66~~52.68	46.06	~~49.91~~53.66	~~48.26~~50.62	~~40.10~~48.94	~~43.36~~44.24	~~45.84~~49.36	~~46.46~~50.33
Natural gas, per KCF	~~6.92~~6.45	~~6.30~~5.81	~~4.69~~2.96	4.19	~~1.49~~1.87	~~0.47~~0.58	~~4.83~~3.75	~~2.20~~2.35	~~5.07~~4.05	~~4.54~~3.62
Total hydrocarbons, per BOE	39.96	40.51	28.62	30.64	44.85	34.60	36.69	33.31	25.29	35.39
Average production cost, per BOE	~~11.08~~8.12	~~10.93~~8.85	~~5.72~~3.08	4.35	9.64	6.68	5.96	8.36	7.11	6.33
Equity-accounted entities		~~14.08~~	~~7.93~~	~~6.48~~	~~11.61~~	~~14.49~~	~~9.18~~
~~Equity-accounted entities~~
Oil and condensates, per BBL			~~18.03~~17.95		38.34		~~27.89~~44.43	~~38.18~~41.49		~~35.15~~38.65
Natural gas, per KCF			~~3.78~~2.63		7.34		6.06	4.19		4.64
Total hydrocarbons, per BOE				~~9.27~~	~~4.24~~17.35		~~5.30~~39.65		36.76	26.50	28.30
Average production cost, per BOE			~~8.98~~5.94		3.45		11.64	1.99		2.71
2018				~~8.67~~	~~16.48~~		~~14.51~~
~~2016~~
Consolidated subsidiaries
~~Oil and condensates, per BBL~~	~~33.19~~	~~39.97~~	~~39.43~~	~~33.05~~	~~41.92~~	~~39.61~~	~~36.89~~	~~34.86~~	~~37.96~~	~~39.33~~
~~Natural gas, per KCF~~	~~4.93~~	~~4.49~~	~~3.29~~	~~3.82~~	~~1.41~~	~~0.34~~	~~3.50~~	~~1.94~~	~~3.60~~	~~3.20~~
~~Average production cost, per BOE~~	~~9.69~~	~~9.31~~	~~4.89~~	~~6.34~~	~~12.09~~	~~7.58~~	~~6.14~~	~~8.70~~	~~7.08~~	~~7.79~~
~~Equity-accounted entities~~
Oil and condensates, per BBL	61.58	64.51	~~17.93~~65.95	62.97	68.76	66.78	~~34.95~~68.35	~~32.39~~57.22	68.72	~~30.85~~65.79
Natural gas, per KCF	8.37	7.99	~~1.85~~4.97	4.85	2.38	0.77	~~5.92~~6.11	~~4.17~~2.38	4.80	~~4.25~~5.17
Average production cost, per BOE	9.97	8.39	~~9.74~~3.16	3.87	10.25	6.53	~~8.19~~4.68	~~8.81~~10.56	7.09	~~8.34~~6.50
Total hydrocarbons, per BOE	53.01	56.07	43.34	36.22	58.59	46.98	50.98	46.63	28.99	48.04
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

Development ~~activities~~well activity

In ~~2016,~~2019, a total of ~~296~~241 development wells were drilled ~~(118.7~~(85.4 of which represented Eni’s share) as compared to ~~335~~209 development wells drilled in ~~2015 (132.4~~2018 (80.2 of which represented Eni’s share) and ~~440~~178 development wells drilled in ~~2014 (191~~2017 (90.7 of which represented Eni’s share).

The drilling of 6884 development wells ~~(28.6~~(21.0 of which represented Eni’s share) is currently underway.

TABLE OF CONTENTS

The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, ~~2016.~~2019. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

~~Development Well Activity~~

	Net wells completed						Wells in progress at 31 Dec.		Net wells completed						Wells in progress at 31 Dec.
	2014		2015		2016		2016		2019		2018		2017		2019
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy	12.5		6.0		4.0		1.0	1.0	3.0		3.0		2.6		2.0	1.6
Rest of Europe	9.8	1.0	10.2	0.1	5.6		4.0	0.6	3.3		2.8	0.3	2.7	0.2	25.0	2.2
North Africa	54.5	1.0	30.5	2.8	38.6	1.2	18.0	10.0	5.0	1.1	9.6	0.5	5.1		2.0	1.1
Egypt									33.5		30.7		49.7	2.3	9.0	3.5
Sub-Saharan Africa	31.6		22.0	2.5	21.2	0.2	36.0	14.0	7.0		7.3	0.1	8.6		19.0	3.4
Kazakhstan	1.5		4.7		4.6	3.0	0.8		0.9		0.9		1.2		1.0	0.3
Rest of Asia	54.2	1.6	29.7	5.9	31.6	0.5	2.0	0.3	27.3	2.2	21.9		15.0	0.2	25.0	7.9
Americas	22.1	0.7	17.4	0.1	9.9	1.3	4.0	1.9	2.1		2.3		3.1		1.0	1.0
Australia and Oceania	0.1	0.4	0.5								0.8
Total including equity-accounted entities	186.3	4.7	121.0	11.4	115.5	3.2	68.0	28.6	82.1	3.3	79.3	0.9	88.0	2.7	84.0	21.0

Exploration ~~activities~~well activity

In ~~2016,~~2019, a total of 1631 new exploratory wells were drilled ~~(10.2~~(16.3 of which represented Eni’s share), as compared to 2924 exploratory wells drilled in ~~2015 (19.1~~2018 (15.6 of which represented Eni’s share) and 4425 exploratory wells drilled in ~~2014 (25.8~~2017 (15.9 of which represented Eni’s share).

~~TABLE OF CONTENTS~~

The overall commercial success rate was ~~50% (50%~~36% (47% net to Eni) as compared to ~~16.7% (25.1%~~62% (66% net to Eni) and ~~31.3% (38%~~60% (52% net to Eni) in ~~2015~~2018 and ~~2014,~~2017, respectively.

The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, ~~2016.~~2019. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. For further information on the ageing of suspended wells see note 11 on Consolidated Financial Statements.

~~Exploratory Well Activity~~

	Net wells completed						Wells in progress at Dec. 31(1)		Net wells completed						Wells in progress at Dec. 31(1)
	2014		2015		2016		2016		2019		2018		2017		2019
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy		0.6				1.0	4.0	2.3		0.5	1.8
Rest of Europe		4.3		2.2	0.1	0.4	9.0	2.3	0.3	1.4		0.5	1.2	1.3	14.0	3.5
North Africa	3.5	4.3	3.3	5.8	6.0	1.8	16.0	12.3	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	7.3	7.3	0.6	2.9	0.1	1.1	32.0	17.0	0.5	0.9	0.4		2.9	0.3	38.0	18.4
Kazakhstan							6.0	1.1							6.0	1.1
Rest of Asia	1.3	4.3		3.4		0.9	8.0	3.2		1.7	2.2	2.6			11.0	3.8
Americas	2.0	1.4	1.0	0.3		1.0	3.0	1.5			4.0		0.5		3.0	1.4
Australia and Oceania		0.9					1.0	0.3		0.5					1.0	0.3
Total including equity-accounted entities	14.1	23.1	4.9	14.6	6.2	6.2	79.0	40.0	5.8	6.5	10.1	5.1	7.6	7.0	98.0	47.7

(1)

Includes temporary suspended wells pending further evaluation.

Oil and gas properties, operations and acreage

In ~~2016,~~2019, Eni performed its operations in ~~44 countries~~41 Countries located in five continents. As of December 31, ~~2016,~~2019, Eni’s mineral right portfolio consisted of ~~780~~873 exclusive or shared rights of exploration and development activities for a total acreage of ~~323,896~~357,854 square kilometers net to Eni (406,505 square kilometers net to Eni as of ~~which developed~~December 31, 2018). Developed acreage ~~of 32,489~~was 29,283 square kilometers and undeveloped acreage ~~of 291,407~~was 328,571 square kilometers net to Eni.

In ~~2016, changes in total net acreage mainly derived from: (i)~~2019 new leases were purchased or been awarded in Bahrain, the United Arab Emirates, Mozambique, Algeria, Argentina, Egypt, Cyprus, Norway, Tunisia, Kazakhstan, Ivory Coast and Mexico for a total increase in acreage of approximately 33,500 square kilometers. Interest increase were reported mainly in ~~Egypt, Ghana, Morocco, Montenegro, Norway~~Myanmar, Indonesia and the United ~~Kingdom~~States for a total acreage of approximately ~~10,500~~970 square kilometers; (ii) the total relinquishment of licenses mainly in Australia, Gabon, India, Liberia, Norway and the United States covering an acreage of approximately 13,000 square kilometers; and (iii) partial relinquishment in Australia, Portugal and South Africa or interest reduction mainly in Myanmar, for approximately 17,000 square kilometers.

4345

TABLE OF CONTENTS

kilometers. Relinquishment for the year of licenses related mainly to India, China, Vietnam, Portugal, Ecuador and the United Kingdom covering an acreage of approximately 27,600 square kilometers. Partial relinquishment were reported mainly in Indonesia, South Africa and Pakistan or interest reduction mainly in Oman, Morocco, Cyprus, Indonesia and Mozambique for approximately 55,500 square kilometers.

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, ~~2016.~~2019. A gross acreage is one in which Eni owns a working interest.

December 31,
~~2015~~2018

December 31, ~~2016~~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

~~45,123~~46,332

~~295~~309

~~15,693~~15,282

~~51,758~~58,616

~~67,451~~73,898

~~10,827~~9,278

~~34,553~~28,750

~~45,380~~38,028

Italy

~~16,975~~14,987

~~146~~128

~~10,498~~9,545

~~10,320~~7,595

~~20,818~~17,140

~~8,775~~7,887

~~7,992~~5,845

~~16,767~~13,732

Rest of Europe

~~28,148~~31,345

~~149~~181

~~5,195~~5,737

~~41,438~~51,021

~~46,633~~56,758

~~2,052~~1,391

~~26,561~~22,905

~~28,613~~24,296

Cyprus

~~10,018~~17,111

~~12,523~~26,614

~~10,018~~14,557

~~10,018~~

~~Croatia~~

~~987~~

~~1,975~~

~~987~~

~~987~~14,557

Greenland

1,909

4,890

1,909

Montenegro

614

1,228

614

Norway

~~3,114~~2,628

~~57~~131

~~2,311~~4,828

~~6,045~~14,577

~~8,356~~19,405

~~452~~777

~~2,156~~3,436

~~2,608~~4,213

Portugal

~~6,370~~

33,182

~~4,547~~

~~3,182~~

United Kingdom

~~1,905~~4,018

~~67~~38

909

~~5,932~~1,011

~~6,841~~1,920

~~613~~614

~~5,715~~506

~~6,328~~1,120

Other Countries

~~3,845~~1,883

~~11~~2

~~6,273~~2,701

~~2,967~~1,883

AFRICA

~~157,441~~165,699

~~264~~260

~~46,384~~54,351

~~264,600~~273,494

~~310,984~~327,845

~~11,729~~15,194

~~140,947~~148,431

~~152,676~~163,625

North Africa

~~25,699~~33,932

~~121~~69

~~14,292~~17,628

~~54,122~~51,716

~~68,414~~69,344

~~5,738~~7,966

~~23,654~~23,907

~~29,392~~31,873

Algeria

~~1,179~~1,155

~~42~~47

~~3,222~~12,157

~~187~~279

~~3,409~~12,436

~~1,148~~5,472

~~31~~100

~~1,179~~

~~Egypt~~

~~9,668~~

~~57~~

~~5,508~~

~~22,523~~

~~28,031~~

~~2,074~~

~~8,591~~

~~10,665~~5,572

Libya

13,294

~~1,962~~1,963

24,673

~~26,635~~26,636

958

12,336

13,294

Morocco

17,925

~~6,739~~23,900

~~2,696~~10,755

Tunisia

1,558

~~3,600~~3,508

2,864

~~3,600~~6,372

~~1,558~~1,536

716

~~1,558~~2,252

Egypt

5,248

5,659

15,710

21,369

2,113

5,500

7,613

Sub-Saharan Africa

~~131,742~~126,519

~~143~~135

~~32,092~~31,064

~~210,478~~206,068

~~242,570~~237,132

~~5,991~~5,115

~~117,293~~119,024

~~123,284~~124,139

Angola

~~4,404~~5,303

~~57~~45

~~8,160~~8,349

~~12,892~~7,841

~~21,052~~16,190

~~1,024~~1,073

~~3,343~~2,671

~~4,367~~3,744

Congo

~~1,354~~1,471

~~1,794~~1,430

~~657~~1,320

~~2,451~~2,750

~~971~~843

~~197~~628

~~1,168~~1,471

Gabon

~~7,615~~4,107

~~6,217~~4,107

Ghana

579

226

1,127

1,353

100

~~1,353~~

~~579~~479

579

Ivory Coast

~~429~~2,905

4,921

3,724

Kenya

43,948

50,677

43,948

Mozambique

978

25,304

4,349

Nigeria

7,722

21,059

8,631

29,690

3,099

3,543

6,642

South Africa

26,202

~~954~~55,677

~~286~~22,271

~~286~~

~~Kenya~~

~~40,426~~

~~61,363~~

~~41,173~~

~~Liberia~~

~~1,841~~

~~2,341~~

~~585~~

~~Mozambique~~

~~1,956~~

~~3,911~~

~~1,956~~

~~Nigeria~~

~~7,432~~

~~34~~

~~22,138~~

~~8,631~~

~~30,769~~

~~3,996~~

~~3,374~~

~~7,370~~

~~South Africa~~

~~32,881~~

~~65,696~~

~~26,279~~

~~26,279~~22,271

Other Countries

33,304

46,463

33,304

ASIA

~~117,183~~181,414

~~59~~69

~~18,165~~12,686

~~198,024~~267,851

~~216,189~~280,537

~~6,016~~3,199

~~103,745~~139,497

~~109,761~~142,696

Kazakhstan

~~869~~1,543

2,391

~~2,542~~5,124

~~4,933~~7,515

442

~~427~~1,718

~~869~~2,160

Rest of Asia

~~116,314~~179,871

~~53~~61

~~15,774~~10,295

~~195,482~~262,727

~~211,256~~273,022

~~5,574~~2,757

~~103,318~~137,779

~~108,892~~140,536

~~China~~Bahrain

~~7,069~~

~~77~~

~~7,056~~

~~7,133~~

~~13~~

~~7,056~~

~~7,069~~

~~India~~

~~6,167~~

~~13,110~~2,858

2,858

China

5,228

India

5,244

~~5,244~~

Indonesia

~~25,124~~23,769

~~14~~13

~~4,246~~2,605

~~30,243~~20,898

~~34,489~~23,503

~~1,603~~1,029

~~23,578~~14,926

~~25,181~~15,955

Iraq

446

1,074

446

Lebanon

1,461

3,653

1,461

Myanmar

~~20,050~~13,558

24,080

~~13,558~~14,147

~~Pakistan~~Oman

~~8,810~~77,146

~~14~~

~~10,177~~

~~11,486~~

~~21,663~~

~~3,332~~

~~5,414~~

~~8,746~~

~~Russia~~

~~20,862~~

~~62,592~~90,760

~~20,862~~49,918

Pakistan

5,786

3,390

8,370

11,760

872

2,907

3,779

Russia

17,975

53,930

17,975

Timor Leste

1,230

~~1,538~~2,612

~~1,230~~1,620

Turkmenistan

180

200

180

United Arab Emirates

1,472

2,949

17,058

20,007

217

10,170

10,387

Vietnam

23,132

~~30,777~~23,908

~~23,132~~18,553

Other Countries

3,244

14,600

3,244

AMERICAS

~~6,628~~9,303

~~148~~229

~~4,948~~2,299

~~8,154~~17,763

~~13,102~~20,062

~~3,208~~1,024

~~2,488~~9,679

~~5,696~~10,703

Ecuador

~~1,985~~

1,985

~~1,985~~

~~Mexico~~

~~67~~

~~67~~Mexico

~~67~~

~~Trinidad & Tobago~~3,000

~~66~~10

114

~~382~~5,455

5,469

~~382~~14

~~66~~3,092

~~66~~3,106

United States

~~2,118~~2,191

~~129~~205

~~1,320~~1,024

~~997~~1,683

~~2,317~~2,707

~~660~~513

~~526~~1,422

~~1,186~~1,935

Venezuela

1,066

1,261

1,543

2,804

497

569

1,066

Other Countries

~~1,326~~1,061

~~5,547~~9,082

~~1,326~~4,596

AUSTRALIA AND OCEANIA

~~16,333~~3,757

~~14~~6

~~1,140~~728

~~15,728~~2,860

~~16,868~~3,588

~~709~~588

~~9,674~~2,214

~~10,383~~2,802

Australia

~~16,333~~3,757

~~14~~6

~~1,140~~728

~~15,728~~2,860

~~16,868~~3,588

~~709~~588

~~9,674~~2,214

~~10,383~~2,802

Total

~~342,708~~406,505

~~780~~873

~~86,330~~85,346

~~538,264~~620,584

~~624,594~~705,930

~~32,489~~29,283

~~291,407~~328,571

~~323,896~~357,854

(a)

Square kilometers.

(b)

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

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The table below sets forth, as of December 31, 2019 and by main producing countries in each geographic area, Eni’s producing assets, the year in which Eni’s activities started, the Eni’s participating interest in each assets and whether Eni is operator of the asset.


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%), Marulk (13.92%), Balder & Ringhorne (62.64%) and Ringhorne East (48.71%)
		Non-operated	Åsgard (15.35%), Kristin (13.31%), Heidrun (3.60%), Mikkel (33.67%), Tyrihans (12.54%), Morvin (20.88%), Great Ekofisk Area (8.62%), Boyla (13.92%), Brage (8.53%) and Snorre (12.91%)
United Kingdom	(1964)	Operated	Liverpool Bay (100%) and Hewett Area (89.3%)
		Non-operated	Elgin/Franklin (21.87%), Glenelg (8%), J Block (33%), Jasmine (33%) and Jade (7%)
NORTH AFRICA
Algeria (b)	(1981)	Operated	Sif Fatima II (49%), Zemlet El Arbi (49%), Ourhoud II (49%), Blocks 403a/d (from 65% to 100%), Block ROM North (35%), Blocks 401a/402a (55%), Block 403 (50%) and Block 405b (75%)
		Non-operated	Block 404 (12.25%) and Block 208 (12.25%)
Libya (b)	(1959)	Non-operated	Onshore contract areas: Area A (former concession 82 – 50%), Area B (former concession 100/Bu-Attifel and Block NC 125 – 50%), Area E (El Feel – 33.3%) and Area D (Block NC 169 – 50%)
			Offshore contract areas: Area C (Bouri – 50%) and Area D (Block NC 41 – 50%)
Tunisia	(1961)	Operated	Maamoura (49%), Baraka (49%), Adam (25%), Oued Zar (50%), Djebel Grouz (50%), MLD (50%) and El Borma (50%)
EGYPT (b)(c)	(1954)	Operated	Shorouk (Zohr – 50%), Nile Delta (Abu Madi West/Nidoco – 75%), Sinai (Belayim Land, Belayim Marine and Abu Rudeis – 100%), Meleiha (76%), North Port Said (Port Fouad – 100%), Temsah (Tuna, Temsah and Denise – 50%), South West 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 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%), Development Area Lianzi in the Blocco 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%), Loango (42,5%), Ikalou (100%), Djambala (50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%), M’Boundi (82%), Kouakouala (74.25%), Zingali (100%) and Loufika (100%)
		Non-operated	Pointe-Noire Grand Fond (35%) 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%)
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%)
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 5 (40%)

(a)

Assets held by the Vår Energi equity-accounted entities (Eni’s interest 69.6%).

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(b)

In certain extractive initiatives, Eni and the host Country agree to assign the operatorship of a given initiative to an incorporated joint venture, a so called operating company. The operating company in its capacity as the operator is responsible of managing extractive operations. Those operating companies are not controlled by Eni.

(c)

Eni’s working interests (and not participating interests) are reported. This include Eni’s share of costs incurred on behalf of the first party accordingly to the terms of PSAs inforce in the Country.

(d)

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

(e)

Eni and Shell are co-operators.

(f)

Eni is leading a consortium of partners including international companies and the national oil company Missan Oil.

The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, ~~2016.~~2019. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same borehole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is ~~9,399 (3,737.6~~8,292 (2,848.8 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, ~~2016~~ 2019(a)

(units)	Oil Wells				Natural gas Wells				Oil Wells				Natural gas Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Italy		243.0		197.1		616.0		532.4		204.0		158.2		441.0		383.0
Rest of Europe		395.0		72.5		160.0		88.1		657.0		106.2		207.0		67.0
North Africa		1,813.0		963.8		225.0		98.1		589.0		245.7		125.0		67.5
Egypt										1,196.0		513.2		141.0		43.6
Sub-Saharan Africa		3,020.0		590.3		350.0		28.8		2,620.0		538.0		201.0		27.0
Kazakhstan		204.0		54.8						204.0		55.8		1.0		0.3
Rest of Asia		727.0		479.1		1,036.0		393.2		990.0		367.7		180.0		63.6
Americas		264.0		133.3		321.0		98.5		250.0		128.4		284.0		81.6
Australia and Oceania		7.0		3.8		18.0		3.8						2.0		2.0
Total including equity-accounted entities		6,673.0		2,494.7		2,726.0		1,242.9		6,710.0		2,113.2		1,582.0		735.6

(a)

Multiple completion wells included above: ~~approximateley 2,128 (741.9~~approximately 1,403 (382.8 net to Eni).

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

- Concession contracts are currently applied mainly in OECD countries and regulate relationships between States and oil companies with regards to hydrocarbon exploration and production activity. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions obtained. As compensation for mineral concessions, it pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with local tax legislation. Both exploration and production licenses are granted generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases): the term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right.

In Particular, Eni’s exploration and production activities are regulated by concession contracts or a similar scheme mainly in Italy, Ghana, Tunisia, the United Arab Emirates, the United Kingdom, the United States, certain assets in Nigeria, Angola and Australia as well as onshore permits in Pakistan. In Norway, Eni’s activities are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.

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- Eni operates under Production Sharing Agreement (PSA) in several of the foreign jurisdictions mainly in African, Middle Eastern, Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil).

A similar scheme applies to some Service contracts.

Eni’s exploration and production activities are regulated by PSA or scheme similar in Algeria, Angola, China, Congo, Egypt, Indonesia, Libya, Mexico, 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 has been operating in Italy since 1926. In 2016, Eni’s oil and gas production amounted to 127 KBOE/d.~~ Eni’s activities in Italy are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley. ~~Eni’s exploration and development activities in Italy are regulated by concession contracts (50 operated~~Eni operates 31 onshore and ~~64 operated offshore) and exploration licenses (12~~63 offshore productive concessions as well as 13 onshore and 9 ~~offshore).~~offshore exploration licenses. In 2019, Italy accounted for approximately 7% of Eni’s total worldwide production of oil and natural gas.

Eni’s domestic production in 2019 was accounted for 39% in the Adriatic and Ionian Seas, 47% in the Central Southern Apennines and 10% in Sicily.

Development activities in 2019 mainly concerned: (i) maintenance and production optimization, at offshore fields in the Adriatic Sea; (ii) the progress in development 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 in the Val d’Agri concession with improvement in environmental standards and plant safety as well in operational performance.

In Italy, a new law has been enacted effective February 12, 2019, which requires Italian administrative bodies to adopt a plan indented 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 any material impacts on the Group future results of operations and cash flow. Currently, thirty-three concessions for hydrocarbon development and production have expired, including Val d’Agri which is the largest Italian concession of the Company. Applications have been timely filed with Italian administrative authorities 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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~~The Adriatic and Ionian Seas represent Eni’s main production area, accounting~~Pending the administrative resolution, the current law provides for 52% of Eni’s domestic production in 2016. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela-Angelina, Hera Lacinia, Bonaccia and Porto Garibaldi. Development activities concerned: (i) maintenance and production optimization, mainly at the ~~Barbara, Cervia/Arianna and Morena fields; and (ii) start-up~~prorogation of the ~~Clara NW~~concessions in accordance to the development ~~project.~~

~~Eni is~~plans agreed with the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region in Southern Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano oil center.initial award.

On August 12, 2016 the activity of the Val d’Agri Oil Centre in Viggiano gradually restarted following notification by the Italian Public Prosecutor of Potenza that has definitively repealed the plant seizure, with a four-month and half production shutdown, and by the National Mining Office for Hydrocarbons and Earth Resources of the Ministry of Economic Development that has authorized the plant’s operation. The resumption of production is a result of the completion in June 2016 of certain plant upgrading, which do not alter the plant set up, authorized by the in-charge department of the Italian Ministry of Economic Development in order to address the alleged environmental crimes issued by the public prosecutor.

Eni operates 12 production concessions onshore and 3 offshore Sicily. The main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2016 accounted for approximately 12% of Eni’s production in Italy.

Rest of Europe

Eni’s operations in the Rest of Europe are mainly conducted ~~mainly~~ in ~~Croatia,~~the United Kingdom and in Norway, through Eni’s equity accounted 69.6% interest in Vår Energi. In December 2018, it was finalized the business combination between Point Resources AS and Eni Norge AS, fully-owned by HitecVision and Eni respectively, with the ~~UK.~~ creation of Vår Energi AS, an equity-accounted joint venture. The governance of the new entity is designed to establish joint control of the two shareholders over the combined entity. Therefore, effective at the closing, Eni derecognized the assets and liabilities of Eni Norge and recognized the fair value of the interest retained in the merged company that will be equity-accounted going forward.

In ~~2016,~~2019, the Rest of Europe accounted for ~~12%~~9% of Eni’s total worldwide production of oil and natural gas.

~~Croatia~~United Kingdom. ~~Eni has been present~~Development activities mainly concerned the drilling of four wells, which were already started up in ~~Croatia since 1996.~~production, at the Elgin Franklin field (Eni’s interest 21.87%) and Joanne and Jasmine fields (Eni’s interest 33%).

North Africa

Eni’s operations in North Africa are mainly conducted in Algeria, Libya and Tunisia. In ~~2016,~~2019, North Africa accounted for 21% of Eni’s total worldwide production of oil and natural ~~gas averaged approximately 24 mmCF/d. Activities are deployed~~gas.

Algeria. In February 2019, Eni completed the acquisition of the 49% interest in the ~~Adriatic Sea near~~Sif Fatima II, Zemlet El Arbi and Ourhoud II concessions in the ~~city~~Berkine Nord area, following the agreements signed in 2018. The ongoing activities concerned: (i) the fast-track development activity of ~~Pula.~~

~~Exploration~~the three concessions. In particular, during the year, oil production start-up was achieved by means of 7 production wells and the connection to the existing facilities of the BRN area in the Block 403 (Eni’s interest 50%). In the first months of 2020, gas production ~~activities in Croatia are regulated by PSAs.~~

~~The main producing gas fields are Annamaria, Ivana, Ika & Ida, Ika JZ, Ana, Marica and Katarina and are operated by Eni through a 50/50 joint operating company~~started up with the ~~Croatian oil company INA.~~

~~TABLE OF CONTENTS~~

~~Norway. Eni has been operating in Norway since 1965. Eni’s activities are performed in~~drilling of 2 wells and the ~~Norwegian Sea, in~~connection of 2 additional wells to the ~~Norwegian section~~existing facilities, following the completion of the ~~North Sea and~~pipeline from BRN to the MLE treatment plant in ~~the Barents Sea. Eni’s production in Norway amounted to 131 KBOE/d in 2016.~~

Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.

Eni currently holds interests in 10 production areas in the Norwegian Sea. The principal producing fields are Åsgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.17%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%), MarulkBlock 405b (Eni operator with a ~~20%~~75% interest); and ~~Morvin (Eni’s interest 30%) which in 2016 accounted for 56% of Eni’s production in Norway.~~

~~Eni holds interests in 2 production licenses~~(ii) exploration and delineation activities in the ~~Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%)~~area. In particular, in PL 018, which in 2016 produced approximately 16 KBOE/d net to Eni and accounted for 12% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.

~~Eni holds interests in 17 exploration and development licenses in the Barents Sea, of which Eni operates 11 licenses.~~

~~Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest).~~

In March 2016, production start-up was achieved at the Goliat field (Eni operator with a 65% interest) in PL 229 and in 2016 accounted for 25% of Eni’s production in Norway. Field production reached the target of 100 KBOE/d (65 KBOE/d net to Eni) and during the year peak production of approximately 114 KBOE/d (approximately 74 KBOE/d net to Eni) was achieved. The license expires in 2042.

Other development activities concerned: (i) the infilling activities in order to support production at the Ekofisk and Eldfisk in the PL 018; and (ii) the maintenance and optimization of the production at the Asgard (Eni’s interest 14.82%), Heidrun (Eni’s interest 5.17%) and Norne Outside (Eni’s interest 11.5%) in the Norwegian Sea.

In 2016 Eni was awarded the following exploration licenses: (i) an 11.5% interest in the PL 128D in the Norwegian Sea; (ii) the operatorship and a 70% interest in the PL 816 in the Norwegian section of the North Sea; and (iii) the operatorship and a 65% interest in the PL 229D and a 30% interest in the PL 849 in the Barents Sea.

In January 2017, Eni was awarded the PL 28E license (Eni’s interest 11.5%) in the Norwegian Sea and the PL 900 (Eni operator with a 90% interest) and PL 901 (Eni’s interest 30%) in the Barents Sea.

~~At the beginning of 2017,~~2019 exploration activity yielded positive results with an oil and gas discovery in the ~~PL 128/128D~~Ourhoud II concession.

Development activities in other blocks included: (i) production optimization in the operated Blocks 403a/d and ROM Nord (Eni’s interest ~~11.5%~~35%), Blocks 401a/402a (Eni’s interest 55%), Block 405b, Block 403 and Block 404 (Eni’s interest 12.25%); and (ii) the ongoing development activities of the El Merk field in the ~~Norwegian Sea, nearby production facilities of the Norne field~~Block 208 (Eni’s interest ~~6.9%~~12.25%). with the drilling of production and water injection wells.

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~~United Kingdom~~Libya. ~~Eni has been present in the UK since 1964. Eni’s activities are carried out in the British section~~Currently, Libya represents approximately 16% of the ~~North Sea and~~Group’s total production. Notwithstanding, the ~~Irish Sea. In 2016,~~complexity of the geopolitical environment, in 2019 Eni’s ~~net production of oil and gas averaged 60 KBOE/d. Exploration and production~~ activities in the ~~UK are regulated by concession contracts.~~Country

[MISSING IMAGE: tm1923634d1-mp_libya4c.jpg]

~~Eni currently holds interests in 5~~progressed smoothly and achieving the planned production ~~areas~~mainly from Wafa production optimization activities and new compression, upgrading of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other fields are Elgin/Franklin (Eni’s interest 21.87%), J Block and Jasmine (Eni’s interest 33%) and Jade (Eni’s interest 7%), which in 2016 accounted for 63% of Eni’s productiontreatment plants in the ~~UK.~~

~~The Phase 2 development activities of the West Franklin field (Eni’s interest 21.87%) was completed and during the year peak production of 61 KBOE/d (13 KBOE/d net to Eni) was achieved.~~

~~Eni holds interest in 18 exploration licenses, of which 2 are partially in development, with interest ranging from 7% to 100%. Out of the total, 11 are operated by Eni.~~

~~In 2016, Eni was awarded the operatorship of PL2287, PL2288 and PL2292 licences with a 100% interest in the Irish Sea and Liverpool Bay area, nearby Eni operated production assets.~~

~~North Africa~~

~~Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2016, North Africa accounted for 37% of Eni’s total worldwide production of oil and natural gas.~~

~~Algeria. Eni has been present in Algeria since 1981. In 2016, Eni’s oil&gas production averaged 85 KBOE/d.~~

Operated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the country: (i) blocks 403a/d (Eni’s interest from 65% to 100%); (ii) block ROM North (Eni’s interest 35%); (iii) blocks 401a/402a (Eni’s interest 55%); (iv) block 403 (Eni’s interest 50%); (v) block 405b (Eni’s interest 75%); and (vi) block 212 (Eni’s interest 22.38%) with discoveries already made. In addition, Eni holds interest in the non-operated block 404 and block 208 with a 12.25% stake.

~~Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.~~

~~Production in blocks 403a/d and ROM North comes mainly from the HBN and ROM and satellites fields and represented approximately 21% of Eni’s production in Algeria in 2016.~~

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Production in blocks 401a/402a comes mainly from the ROD/SFNE and satellites fields and accounted for approximately 17% of Eni’s production in Algeria in 2016. In 2016, Eni signed with the relevant Authorities a pre-unitization agreement of the SF-SFNE fields and a 10-year extension of the fields in the area. Development activities mainly concerned infilling and optimizations activities at the ROD field (Eni operator with a 66% interest).

~~The main fields in block 403 are BRN, BRW and BRSW, which accounted for approximately 9% of Eni’s production in Algeria in 2016.~~

~~The main fields in block 404 are HBN and HBNS and satellites, which accounted for approximately 21% of Eni’s production in Algeria in 2016.~~

~~Production in block 405b comes mainly from MLE and CAFC projects and accounted for approximately 13% of Eni’s production in the country in 2016.~~

Production start-up was achieved at the CAFC oil project at the end of the year, with start-up of 6 wells and linkage at the treatment facilities of the area. The development activities are expected to complete during 2017.

~~Development and optimization activities progressed at the MLE and CAFC gas fields by means of construction and infilling activities, as well as production optimization.~~

~~The El-Merk field is the main production project in the block 208 and accounted for approximately 18% of Eni’s production in Algeria in 2016.~~

~~Egypt~~. Eni has been present in Egypt since 1954. In 2016, Eni’s share of production in this country amounted to 170 KBOE/d and accounted for 10% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Melehia (Eni’s interest 76%) and the Ras Qattara (Eni’s interest 75%) concessions. Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (Eni’s interest 50%), Baltim (Eni’s interest 50%), Ras el Barr (Eni’s interest 50%, non operated) and the Abu Madi West (Eni’s interest 75%), located offshore the Nile Delta. In 2016, production from these large concessions accounted for approximately 98% of Eni’s production in Egypt.

~~Exploration and production activities in Egypt are regulated by Production Sharing Agreements.~~

In February 2016, the Egyptian Ministry of Petroleum and Mineral Resources approved the award to Eni the Zohr Development Lease that allows the start-up of the development program at the Zohr gas field in the operated Shorouk concession (Eni’s interest 100%) and, as a consequence, the FID was sanctioned and added proved undeveloped reserves for the field. The first gas is expected at the end of 2017. Based on the production test, delineation and development drilling activities management believes that this discovery contains a large amount of gas resources. Drilling activities will continue in 2017 together with construction activities of onshore gas treatment plant and offshore facilities installation.

In 2016, Eni signed two agreements to sell a 40% overall interest in the Shorouk concession. The agreements concerned the sale of: (i) a 10% interest to BP for a consideration amount of $375 million and the pro-quota reimbursement of past expenditures, which amount so far at approximately $150 million; and (ii) a 30% interest to Rosneft for a consideration amount of $1.125 million and the pro-quota reimbursement of past expenditures, which amount so far at approximately $450 million. In addition, the new partners have an option to buy a further 5% interest under the same terms.

In February 2017, Eni signed a deed completing the sale of 10% interest to BP, with all authorizations from Egypt’s authorities. The sale agreement with Rosneft will be finalized in the first half of 2017 and subject to necessary authorizations from the country’s authorities.

During the year targeting production of 85.5 KBOE/d net to Eni was achieved at the Nidoco NW field and satellites as a part of the Great Nooros Area project in the Abu Madi West concession. The start-up was achieved in 13 months following the announcement of the commercial discovery in July 2015 by means of the exploration successes in the NoorosMellitah area and ~~the drilling of the new development wells. Production plateau of 160 KBOE/d is expected in 2017 with the completion of ongoing development activities.~~

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~~Other development activities concerned: (i) ongoing activity of the sub-sea END Phase 3 development project in the Ras El Barr concession (Eni’s interest 50%) with the drilling~~Sabratha platform, and completion of two wells; (ii) infilling activities and production optimization at the Sinai 12 (Eni’s interest 100%), Ashrafi (Eni’s interest 25%) and Meleiha (Eni’s interest 76%) concessions to support production capacity; (iv) start-upBahr Essalam phase 2. The worsening of the ~~onshore gas treatment plant in the Meleiha concession.~~

In December 2016 Concession Agreements were ratified for the North El Hammad (Eni operator with a 37.5% interest) and North Ras El Esh (Eni’s interest 50%) blocks, located in the conventional offshore of the Mediterranean Sea.

Exploration activity yielded positive results with the delineation drilling activity of the Baltim South West (Eni operator with a 50% interest), nearby the Great Nooros Area. Based on this ongoing activity management believes that this discovery contains an important gas resource.

~~In the medium term, management expects to increase Eni’s production reflecting additions from ongoing development projects.~~

~~Libya. Eni started operations~~situation in Libya ~~in 1959.~~

~~In recent years, Eni’s production levels in Libya were negatively impacted by~~remains an ~~internal revolution and a change~~area of regime in 2011, which led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political development forced Eni to temporarily interrupt or reduce its production activities, negatively affecting Eni’s results of operations and cash flow until the situation began to stabilize. Although our production levels in Libya since 2015 have returned to the levels achieved prior to the outbreak of the civil war, the geopolitical situation remains unstable and unpredictable. In 2016, Eni’s facilities in Libya produced on average 346 KBOE/d, registering a decrease of approximately 3% compared to 2015.issue. For further information on this matter, see “Item 3 – Risk ~~factors”~~factors – Political considerations”.

Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).

~~In the exploration phase,~~The rights of Eni ~~is operator in the onshore contract Areas A, B and offshore Area D.~~

~~Exploration and production activities in Libya are regulated by six Exploration and Production Sharing Agreement contracts (EPSA). The licenses of Eni’s~~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 ~~2047~~B as well as in 2043 for ~~oil&gas properties, respectively.~~Contract Area D production.

Tunisia. Development activities concerned production optimization at the producing concessions to mitigate mature fields declines.

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~~Development~~

Egypt

In 2019, Egypt accounted for 19% 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 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 in the onshore Nile Delta nearby to the operated Nooros producing fields (Eni’s interest 75%).

In 2019 development activities ~~concerned:~~were completed: (i) ~~planned facilities downtime~~ at the ~~Mellitah~~Nooros field with the installation of a new gas pipeline to the El Gamil treatment plant ~~the Sabratha~~to production ~~platform~~optimization and ~~treatment facilities of the Western Libyan Gas Project;~~reserves’ recovery maximization; (ii) ~~positioning and installation activities as well as linkage of the new FSO unit~~ at the ~~Bouri production field and start-up at the beginning of 2017; (iii) a second development phase of the Bahr Essalam field (Eni’s interest 50%) with the completion of 10~~Baltim South West offshore wells of which 9 wells already drilled in 2016. The EPCI contract was awarded to supply and installation of flowlines. First gas is expected in 2018; and (iv) the linkage of one additional production wells at the Wafa field (Eni’s interest 50%) and activities in order to mitigate the natural production decline in the area.

~~Morocco~~. In March 2016, Eni signed a Farm-Out Agreement (FOA) with Chariot Oil & Gas that includes the operatorship to Eni and a 40% stake enter into Rabat Deep Offshore exploration permits I-VI offshore Morocco. In October 2016, the relevant country’s Authorities approved the agreement.

~~Tunisia. Eni has been present in Tunisia since 1961. In 2016, Eni’s production amounted to 10 KBOE/d.~~

~~Eni’s activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet.~~

~~Exploration and production in this country are regulated by concessions.~~

~~Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni’s interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar~~project (Eni operator with a 50% interest)~~, Djebel Grouz~~ with production start-up. Development activities concerned the installation of a production platform and the pipeline to the Abu Madi treatment plant; and (iii) at the South West Meleiha (Eni’s interest 100%) production area with the installation of a pipeline connecting to the Meleiha operated treatment plant.

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

Development activities to ramp-up production at the Zohr field (Eni operator with a 50% interest) concerned: (i) the completion of the remaining three 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.

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

As of December 31, 2019, the aggregate development costs incurred by Eni for developing the Zohr project and capitalized in the financial statements amounted to $5.4 billion (€ 4.8 billion at the EUR/USD exchange rate of December 31, 2019). 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.

As of December 31, 2019, Eni’s proved reserves booked at the Zohr field amounted to 807 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) the Sinai concession (Eni operator with an 100% interest), ~~MLD~~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 ~~50%~~76%), Meleiha Deep (Eni’s interest 100%) and ~~El Borma~~Ras Qattara (Eni’s interest ~~50%~~75%) ~~onshore blocks.~~

~~Production optimization represents the main activity currently performed~~concessions in the ~~above listed concessions to mitigate the natural field production decline.~~Western Desert.

Exploration activities yielded positive results ~~with~~with: (i) a gas discovery in the ~~Larich Est-1~~El Qar’a exploration license (Eni’s interest 75%), located in the Nile Delta; (ii) the Sidri oil discovery ~~well, which put into~~ 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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production ~~through a tie-in~~wells connected to the existing ~~treatment facilities of~~facilities; (iii) the ~~MLD concession.~~Basma and Shemy oil discoveries in the Meleiha development lease. Drilling activity has been completed at the Basma discovery and related production wells connected to existing facilities; (iv) the SWM-A-3X gas and condensates discovery in the South West Meleiha concession; and (v) the Nour-1 gas well in the Nour exploration license (Eni’s interest 40%).

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In ~~2016,~~2019, Sub-Saharan Africa accounted for ~~19%~~20% of Eni’s total worldwide production of oil and natural gas.

Angola~~Angola~~. In 2019, Angola accounted for 7% of Eni’s total worldwide production of oil and natural gas.

In January 2020 Eni ~~has been present in Angola since 1980. In 2016, Eni’s production averaged 112 KBOE/d. Eni’s activities are concentrated~~was awarded a 60% interest in the ~~conventional~~Block 28 as operator.

In November 2019 Eni and ~~deep offshore.~~

~~The main Eni’s asset in Angola is~~ the Country’s Authority signed a Memorandum of Understanding which provides for the acquisition of the offshore Block ~~15/06~~1/14 (Eni operator with a ~~36.84%~~35% interest) ~~with the West Hub project, where production started up in 2014~~ and the ~~East Hub development project with production start-up achieved in February 2017. Eni participates in other producing blocks: (i) Block 0 in~~onshore Cabinda Center block (Eni’s interest ~~9.8%~~42.5%) ~~north~~.

In 2019 Eni finalized an extension of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni’s interest 20%) in the deep offshore westexploitation rights until 2032 of ~~Block 0; (iv) the Lianzi Development Area in the Block 14 K/A IMI (Eni’s interest 10%), where a unitization was implemented with the Congo-Brazzaville area; and (v) Development Areas in the former~~ Block 15 (Eni’s interest 20%) in, the ~~deep offshore~~number of the ~~Congo Basin.~~Development Areas has been reduced, joining some of them together.

Eni retains interests in other non-producing concessions, particularly the Block 35/11 (Eni operator with a 30% interest), Block 3/05-A (Eni’s interest 12%), onshore Cabinda North block (Eni’s interest 15%) and the Open Areas of Block 2 assigned to the Gas Project (Eni’s interest 20%).

~~Exploration and production activities in Angola are regulated by concessions and PSAs.~~

The development program of the West Hub project plans to hook up the Block’s discoveries to the N’Goma FPSO in order to support production plateau. In 2016, production start-up was achieved at the M’Pungi and M’Pungi North fields, with a production ramp-up of approximately 81 KBBL/d (approximately 28 KBBL/d net to Eni) in the area. Planned activities included to be put into production 5 additional discoveries.

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~~In February 2017, production start-up was achieved at the East Hub project by means of the linkage of Cabaça South East field to the FPSO Armada Olombendo.~~

~~In the Block 15/06, with the completion of the East Hub project, production derived from five fields. Management plans to put into production two additions discoveries by the end of 2018.~~

~~Early production phase started up at the Mafumeira Sul project in the Block 0.~~ Development ~~activities progressed, with the completion expected during 2017 and a peak production of 100 KBOE/d.~~

~~Other development~~ activities concerned: (i) the completion of the ~~Congo River Crossing~~planned activities at the Vandumbu field in the West Hub project ~~to supply gas~~in the operated Block 15/06 (Eni’s interest 36.84%); and (ii) production ofoptimization at the Mpungi and Sangos fields in the Block 15/06 and in some fields in the Block 0 ~~and 14 to~~(Eni’s interest 9.8%).

Eni owns a 13.6% interest of Angola LNG, ~~liquefaction~~which runs the plant, ~~(Eni’s interest 13.6%) which started up~~located in ~~April 2016~~Soyo, with a treatment capacity of approximately 350 BCF/y of feed gas and a liquefaction capacity of 5.2 mmtonnes/y of LNG. In 2019 production net to Eni averaged approximately 22 KBOE/d. In October 2019 Eni, as operator of ~~6 KBOE/dnet to Eni; and (ii) development program~~a new joint venture (Eni interest 25.6%), signed a commercial agreement with the partners of the ~~Kizomba satellites Phase 2 (Eni’s interest 20%) which will be started up leveraging on~~Angola LNG for the ~~production and treatment facilities in the area.~~

~~In the medium term, management expects to increase Eni’s production to 146 KBOE/d reflecting additions from ongoing~~ development ~~projects.~~

~~Congo. Eni has been present in Congo since 1968. In 2016, production averaged 92 KBOE/d net to Eni.~~

Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. Eni’s main operated oil producing interests in Congo are the Zatchi (Eni’s interest 56%), Loango (Eni’s interest 42.5%), Ikalou (Eni’s interest 100%), Djambala (Eni’s interest 50%), Foukanda and Mwafi (Eni’s interest 58%), Kitina (Eni’s interest 52%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Nené Marine (Eni 65%), Zingali and Loufika (Eni’s interest 100%) fields.

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~~Other relevant not operated producing areas are represented by a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits.~~

~~Exploration and production activities in Congo are regulated by Production Sharing Agreements.~~

~~In December 2016, production ramp-up was achieved at the Nené Marine field with the completion~~ of the ~~second~~gas fields to support the liquefaction plant. The first development ~~phase,~~project is expected to be sanctioned in ~~2015.~~2020.

~~Development~~Exploration activities progressed at ~~the Litchendjili production field and~~Block 15/06 during the year, ~~peak~~after resumed in 2018. Eni made a promising discoveries with the Agogo oil 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 ~~of approximately 16 KBOE/d was achieved. Gas production feeds the CEC power plant (Eni’s interest 20%).~~

~~In the medium term, management expects to maintain production on the present level.~~

~~Ghana. Eni has been present in Ghana since 2009 and currently is the operator~~capacity of the ~~Offshore Cape Three Points (Eni’s interest 44.44%) permits which is regulated by a concession agreement. The license expires~~two FPSO units installed in ~~2036.~~

~~Development activities concerned~~ the ~~OCTP integrated oil&gas development plan to put into~~area. In 2020 the production the Sankofa, Sankofa East and Gye Nyame discoveries. First oil is expected in 2017 and first gas in 2018. In 2016, the drilling activity of 18 development wells was completed and the renovation of a FPSO unit was performed. Contracts were awarded for the installation of sea-lines and the construction of onshore gas plant.

~~In March 2016, Eni was awarded the operatorship~~start-up of the ~~exploration license Cape Three Points Block 4 (Eni’s interest 42.47%), located in the offshore of the country.~~Agogo discovery was achieved.

~~Mozambique~~Mozambique.. Eni has been present in Mozambique since 2006, following the ~~acquisition~~award of the exploration license relating to gas-rich Area 4

~~offshore Rovuma Basin block, located in the north~~ Offshore of the country. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The other partners in Area 4 are Galp, Kogas, ENH with a participating interest of 10% each and CNPC that holds a 20% indirect participation in Area 4 through its participation in the shareholding of Eni East Africa.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 ~~Anadarko.~~Total. In 2012, Eni made another large gas discovery at the Coral ~~gas discovery~~prospect, which falls entirely in Area 4.

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During the exploration period, which ~~has~~ expired in 2015, six Discovery Areas (DA) were ~~identified in Area 4. Pursuant to the~~identified. Mozambique Decree Law 02/2014 ~~multiple~~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 ~~will give right~~entitles the Concessionaires to develop and to produce in a ~~Development and Production Period of the duration~~term of 30 years, ~~further extendable~~with an extension option pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law.

Following two separate transactions occurred respectively in 2013 and in 2017, Eni ~~also operates the exploration offshore Block A-5A (Eni’s interest 34%),~~divested to CNPC and ExxonMobil indirect interests of 20% and 25% respectively in the ~~deep offshore~~discoveries of ~~Zambesi.~~Area 4, by diluting its participating interest in Mozambique Rovuma Venture SpA, the operator of Area 4 which is a joint

~~In March 2017, ExxonMobil and~~

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operation for IFRS accounting purposes, proportionally-consolidated in the Company Consolidated Financial Statements. Post transactions, Eni ~~signed sale and purchase agreement to acquire~~retains a 25% indirect interest in the Area 4 ~~block, offshore Mozambique.~~concession. The ~~agreed terms include~~other concessionaires of Area 4 are the state-owned oil company ENH, Galp and Kogas, each with a ~~cash price~~10% working interest.

Development activities continued at the Coral South project during 2019. The sanctioned Coral South project includes the construction of FPSO for the gas treatment, liquefaction, storage and export of LNG, with a capacity of approximately ~~$2.8 billion.~~3.4 mmtonnes/y, fed by 6 subsea wells. Production start-up is expected in 2022. The ~~acquisition~~LNG produced will be ~~completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Following completion of~~sold by the transaction, Eni East Africa will be co-owned by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by CNPC. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4 ~~while~~Concessionaires to BP under a long-term contract for a period of twenty years, with an option for an additional ten-year term.

Pre-Development activities progressed at the Mamba Complex discoveries where Eni is expected to coordinate the upstream development and production phase and ExxonMobil ~~will lead~~ the construction and operation phase of natural gas liquefaction facilities onshore. ~~This operating model will enable~~In 2019, the ~~use of best practices~~Mozambique authorities approved the unitization agreement between the Area 1 and ~~skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project.~~

The first plan of development was submitted to the Government of Mozambique in December 2014 in relation to the initial exploitation of the Coral gas resources. The Coral South Development Plan, which was approved by the Government in February 2016, envisages the installation of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG - FLNG) with a capacity of over 3.3 mmtonnes/y fed by 6 subsea wells. Eni expects to produce up to 5 TCF of gas with a start-up expected in mid-2022.Area 4.

In ~~October 2016, Eni and its~~this context, the Area 4 ~~partners signed~~Concessionaire progressed activities towards a ~~binding agreement with BP for the sale~~final investment decision (FID) and towards finalization of the entire volumes of LNG produced by the Coral South Project, for a period of over twenty years. In November 2016, Eni’s Board of Directors approved the investment for the first development phase of the Coral discovery. The FID on the project will turn effective once all Area 4 partners sanctioned it and the project financing for the Rovuma LNG project, which ~~is currently being finalized, will be underwritten.~~

~~The development plan of~~provides the ~~Mamba project, comprises~~ construction of two onshore LNG trains with a ~~combined~~ capacity of 10approximately 7.6 mmtonnes/y ~~and the drilling of 16~~each, feed 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.

In May 2019 Eni completed the purchase of a 10% interest of the deep offshore A5-B, Z5-C and Z5-D blocks from ExxonMobil.

In July 2019 Eni divested a 25.5% interest of the offshore A5-A block to Qatar Petroleum. Following this acquisition Eni retains the operatorship with ~~start-up in 2023. Eni expects to produce up to 14 TCF of gas according to its independent industrial plan, coordinated with the operator of Area 1 (Anadarko). The FID is expected in 2018.~~a 34% interest.

Nigeria. ~~Eni has been present in Nigeria since 1962. In 2016, Eni’s oil&gas production averaged 112 KBOE/d located mainly onshore and offshore the Niger Delta.~~

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%) and OPL 245 (Eni’s interest 50%), holding interests in OML 118 (Eni’s interest 12.5%) and in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the country, Eni also holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% interest in 2 conventional offshore blocks.

In the exploration phase Eni operates offshore OML 134 (Eni’s interest 85%), OPL 2009 (Eni’s interest 49%), and onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in OML 135.

Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for State-owned Company.

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On January 27, 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court, sitting in Abuja, upon request from the Economic and Financial Crime Commission (EFCC), attaching the property OPL 245, pending the Nigerian proceeding. Both Eni and Shell made a prompt application to discharge the Order. On March 17, 2017, the Nigerian Court discharged the Order. On that basis, management has concluded that no impairment of the asset was required. After the inception of the judicial proceeding in Italy, which dates back to July 2014, Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure has engaged a US leading law firm to perform an independent review of the issue. Based on the outcome of this review, during which the law firm appointed by Eni has also assessed material and the information made available from the judicial authorities, no wrongdoing has been detected on Eni side in the awarding process to Eni of the license.

The development activities concerned: (i) drilling activity and production start-up of three additional wells, two production and one water-injection, at the Bonga field in the OML 118 block; (ii) the drilling campaign within the integrated project in the Gbaran-Ubie area in the OML 28 block (Eni’s interest 5%), aimed to supply natural gas to the Bonny liquefaction plant. Start-up was achieved in the second half of 2016; and (iii) the OML 43 block (Eni’s interest 5%), where the development plan of the Forcados-Yokri field provides hook-up the last 12 of 23 production wells already drilled, the upgrading of existing flowstations and the construction of transport facilities. Start-up is expected in the first half of 2017.

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 ~~is operational, with a~~has treatment capacity of approximately 1,236 BCF/y of feed gas ~~corresponding to~~and a production capacity of 22 mmtonnes/y of ~~LNG on six trains.~~LNG. Natural gas supplies to the plant are currently provided under a gas supply agreements ~~with an expiring date in fifteen years~~ from the SPDC JV (Eni’s interest 5%), TEPNG JV and the NAOC JV ~~(operating~~(Eni’s interest 20%). In 2019, the ~~OMLs 60, 61, 62 and 63 blocks) with an average amount of~~Bonny liquefaction plant processed approximately ~~2,825 mmCF/d for the next four years (approximately 265 mmCF/d net to Eni corresponding to approximately 49 KBOE/d).~~1,165 BCF. LNG production is sold under long-term contracts and exported mainly to ~~the United States,~~ Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria ~~LNG Co.~~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.

~~In January 2017, Eni signed with~~Development activities of the ~~Nigerian National Petroleum Corporation (NNPC)~~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 ~~Memorandum~~480 MW. Natural gas production of ~~Understanding, which strengthen cooperation~~the area will support the plant capacity.

Other development activities concerned: (i) infilling program and production optimization in the ~~energy sector.~~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 in “Item 18 – consolidated financial statement – Note 27”.

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Kazakhstan

~~Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2016,~~ Eni’s operations in Kazakhstan mainly regarded the Kashagan and the Karachaganak fields. In 2019, Kazakhstan accounted for 6%8% of ~~its~~Eni’s total worldwide production of oil and natural gas.

~~Kashagan~~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

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the Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000 over an ~~undeveloped~~ area extending for 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources, which ~~will eventually~~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 ~~currently~~ of 16.81%, CNPC with 8.33%, and Inpex with 7.56%.

~~On September 28, 2016,~~In 2019, production ~~re-started~~ at the Kashagan field ~~with~~averaged 53 KBBL/d of liquids and 54 mmCF/d of natural gas net to Eni. The treated gas is delivered to the ~~completion of works to fully replace~~national gas marketing and transportation company (KazTransGas), and the ~~damaged pipelines following~~remaining volumes is utilized as fuel gas. The remaining untreated gas volumes (approximately 43%) is re-injected in the ~~gas leak occurred~~reservoir. The liquid production is stabilized at the ~~end of 2013. The production of 180 KBOE/d was achieved by year-end (31 KBOE/d net~~Bolashak facilities and exported to ~~Eni). The production capacity of 370 KBBL/d planned~~Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline.

Current development plans envisage for increasing the ~~Phase 1 is expected to be achieved during 2017, when gas reinjection comes online.~~

~~The Phase 1 includes a further increase available~~ production capacity up to 450 KBBL/d by ~~installing additional~~upgrading the existing gas compression capacity, ~~for reinjection in~~ the ~~reservoir. The partners submitted~~conversion of production wells into injection wells, the ~~scheme~~debottlenecking and the revamping of ~~this additional phase~~existing facilities with the construction of a new onshore gas treatment plant. A final investment decision has yet to ~~the relevant Kazakh Authorities.~~be made.

Management believes that significant capital ~~expenditures~~expenditure will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and ~~subsequent~~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. ~~In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets.~~

As of December 31, ~~2016,~~2019, Eni’s proved reserves booked for the Kashagan field amounted to ~~608~~661 mmBOE, ~~barely unchanged~~increased from ~~2015.~~614 mmBOE in 2018.

As of December 31, ~~2015, Eni’s proved reserves booked for the Kashagan field amounted to 611 mmBOE, recording an increase of 31 mmBBL compared to 2014 mainly due to lower marker Brent price.~~

~~As of December 31, 2014, Eni’s proved reserves booked for the Kashagan field amounted to 580 mmBOE, barely unchanged compared to 2013.~~

~~As of December 31, 2016,~~2019, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to ~~$9.7~~$10 billion (€~~9.2~~8.9 billion at the EUR/USD exchange rate of December 31, ~~2016)~~2019). This capitalized amount included: (i) ~~$7.2~~$7.4 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) ~~$2.5~~$2.6 billion relating primarily to ~~accrue~~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.

~~As of December 31, 2015, the aggregate costs~~ Cost incurred ~~by Eni for the Kashagan project capitalized~~ in the financial statements amounted to $9.2 billion (€8.4 billion at the EUR/USD exchange rate of December 31, 2015). This capitalized amount included: (i) $6.8 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.4 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years.year were €106 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 ~~2016,~~2019, production of the Karachaganak field averaged ~~231~~46 KBBL/d of liquids ~~(61 KBBL/d net to Eni)~~ and ~~867~~186 mmCF/d of natural gas ~~(230 mmCF/d~~ net to ~~Eni).~~Eni. This field is ~~developed by~~ producing liquids from the deeper layers of the reservoir. The gas is marketed (about ~~51%~~50%) at the Russian gas plant inof Orenburg, ~~and~~ the remaining volumes isare utilized for ~~re-injecting~~re-injection in the higher layers of the reservoir and ~~the production of~~as fuel gas. ~~Approximately 91% of~~Almost the entire liquid production ~~are~~is stabilized at the Karachaganak Processing Complex (KPC) ~~with a capacity of approximately 250 KBBL/d~~ and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. ~~The remaining volumes of non-stabilized liquid production (approximately 16 KBBL/d) are marketed at the Russian terminal in Orenburg.~~

~~The Expansion Project is currently under study. The project targets to install, in stages,~~Within the gas treatment ~~plants~~expansion projects of the Karachaganak field, activities concerned: (i) the Karachaganak Debottlenecking project progressed; (ii) project of the construction of fourth gas re-injection unit was sanctioned and activity started up during the year; and (iii) the Front End Engineering Design of the Karachaganak Expansion Project has been completed. The planned activities include the installation of two additional gas re-injection facilities to support liquids’ production profile. The development plan is currently in the phase of technical and marketing definition of its first development phase, aimed to increase the capacity of gas re-injection.facility.

As of December 31, ~~2016,~~2019, Eni’s proved reserves booked for the Karachaganak field amounted to ~~613~~448 mmBOE, ~~reporting an increase of 26~~slightly decreased from 452 mmBOE ~~from 2015 mainly due to lower marker Brent price.~~in 2018.

As of December 31, ~~2015, Eni’s proved reserves booked~~2019, the aggregate costs incurred by Eni for the Karachaganak ~~field~~project capitalized in the financial statements amounted to ~~587 mmBOE, reporting an increase of 98 mmBOE from 2014 mainly due to lower marker Brent price.~~

As$4.1 billion (€3.7 billion at the EUR/USD exchange rate of December 31, ~~2014, Eni’s proved reserves booked for~~2019). Cost incurred in the ~~Karachaganak field amounted to 489 mmBOE, barely unchanged compared to 2013.~~year were €267 million.

Rest of Asia

Eni’s operations in Rest of Asia are conducted mainly in Indonesia, Iraq and United Arab Emirates. In ~~2016,~~2019, Eni’s operations in the Rest of Asia accounted for 7%approximately 9% of its total worldwide production of oil and natural gas.

~~China~~Iraq. ~~Eni has~~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 ~~present in China since 1984 with activities located in~~already installed; the ~~South China Sea. In 2016, Eni’s~~field reserves will be progressively put into production ~~amounted to 2 KBOE/d.~~

~~Exploration and production activities in China are regulated~~ by ~~Production Sharing Agreements.~~

~~In 2016, hydrocarbons were produced from~~drilling additional productive wells over the ~~offshore Blocks 16/19 through 3 platforms connected to an FPSO.~~next few years.

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Indonesia. ~~Eni has been present in Indonesia since 2001. In 2016, Eni’s production mainly composed of gas, amounted to 14 KBOE/d.~~ Activities are concentrated in the ~~Eastern~~ offshore ~~and onshore~~ of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 1413 blocks.

~~Exploration and production activities~~In 2019, Eni divested to Neptune a 20% interest in ~~Indonesia are regulated by PSAs.~~

~~In 2016 production start-up was achieved at the Bangka project (Eni’s interest 20%) in the East Kalimantan.~~

The ongoing development activities that will ensure gas supplies to the Bontang liquefaction plant include the Jangkrik project (Eni operator with a 55% interest) in the Kalimantan offshore. This project is in the final execution phase with all the deep-offshore development subsea wells already drilled and the Floating Production Unit for gas and condensate treatment in the final stage of construction, as well as the construction of transportation and receiving facilities onshore. Production start-up is planned in 2017.

~~Exploration activities yielded positive results with appraisal activities at the Merakes gas discovery in the deep offshore of~~ the East Sepinggan block, ~~(Eni operator with an 85% interest), nearby~~offshore East Kalimantan, which includes the ~~Jangkrik project.~~

~~Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companies~~Merakes field and the ~~national oil company Missan Oil, holds~~East Merakes discovery. Eni will retain a ~~41.6% interests in~~65% interest and the ~~Zubair oil field.~~

Development and production activities at the Zubair field 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 Production Sharing contracts.operatorship.

In ~~2016, production of~~2019 Eni was awarded the ~~Zubair field averaged 64 KBBL/d net to Eni.~~

At the beginning of March 2016, three new generation plants for the oil, gas and water treatment (Initial Production Facilities - IPF) started. Those plants together with 5 existing restructured and modernized plants increased oil and natural gas treatment capacity of Zubair field to approximately 650 KBBL/d and will ensure the maximization of the associated gas utilization.

~~In addition, these new facilities have also a water re-injection capacity of approximately 300 KBBL/d that will boost the Zubair’s hydrocarbons production and will achieve production plateau.~~

~~The first stage of development activities (Rehabilitation Plan) of the Zubair field were completed with start-up of these new facilities.~~

Ongoing development activities concerned an additional development phase (Enhanced Redevelopment Plan) of the Zubair field, to achieve a production plateau of 700 KBBL/d and will ensure the application of associated gas to power generation.

~~Myanmar~~. Eni has been present in Myanmar since 2014. Eni is operator of four Production Sharing Contracts; two onshore blocks RSF-5 and PSC-K (Eni’s interest 90% in both leases) and two offshore blocks MD-02 and MD-04 (Eni’s interest 40% in both leases). The contracts foresee, for the onshore blocks, anWest Ganal exploration ~~period of six years subdivided into three phases and for the offshore blocks a study period of two years, followed by an exploration period of six years, subdivided in 3 phases.~~

~~Pakistan. Eni has been present in Pakistan since 2000. In 2016, Eni’s production mainly composed of gas amounted to 30 KBOE/d.~~

~~Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).~~

~~Eni’s main permits in the country are Bhit/Bhadra~~block (Eni operator with a 40% interest)~~, Latif (Eni’s interest 33.33%) and Zamzama (Eni’s interest 17.75%), which~~ located in ~~2016 accounted for 79% of Eni’s production~~the deep water Kutei Basin, effective since January 1, 2020.

Development activities concerned the offshore Merakes gas project in ~~Pakistan.~~the operated East Sepinggan block.

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~~Production optimization through~~United Arab Emirates. In 2019, Eni awarded: (i) the operatorship of the Block 1 and 2 with a 70% interest, located offshore Abu Dhabi. The exploration commitment for the first phase consists in exploration studies for the Block 1 and the drilling ~~activities~~ of ~~new development~~two exploration wells ~~represents the main activity currently performed~~and one appraisal well in the ~~above listed fields to mitigate~~Block 2; (ii) three onshore exploration

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concessions in the ~~natural field production decline.~~Emirate of Sharjah with a 75% interest in the operated concession Area A and C and a 50% interest in the participated concession Area B. In January 2020, exploration activities yielded positive results 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.

~~Russia. Eni has been present~~Development activities concerned: (i) the Dalma Gas Development project in ~~Russia through three joint ventures with Rosneft for~~ the ~~development of Fedynsky and Central Barents licenses~~Gasha concession (Eni’s interest ~~33.33%~~25%) ~~located~~. The final investment decision was sanctioned. Start-up is expected in 2022; and (ii) the Nasr Full Field Development project in the ~~Russian Barents Sea and Western Chernomorsky license~~Umm Shaif/Nasr concession (Eni’s interest ~~33.33%~~10%). The program was completed and production ramp-up achieved in the ~~Black Sea since 2013.~~

Following the adoption of EU sanctions measures relating to the upstream sector in Russia, Eni started the required authorization before competent Authorities of the Member States of the European Union who granted the Company and the joint ventures between Eni and Rosneft certain authorization for the execution and financing of the exploration activities in Russia, under the terms of contracts entered into force before the enactment of the relevant sanctions. The current sanctions have delayed and will continue to affect the timing of implementation of the projects. For further information on this matter, see “Item 3 – Risk factors”.

~~Turkmenistan~~. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the country. The license expires in 2032.

~~In 2016, Eni’s production averaged 9 KBOE/d.~~

~~Exploration and production activities in Turkmenistan are regulated by PSAs.~~

Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap arrangement with the Turkmen Authorities, an equivalent amount of oil at the Okarem terminal, close to the South coast of the Caspian Sea. Eni’s entitlement is sold FOB. Associated natural gas is used for gas lift system. The remaining amount is delivered to the national oil company Turkmenneft, via national grid.

~~Production optimization represents the main activity currently performed in the area to mitigate the natural field production decline.~~

~~Vietnam~~. Eni has been present in Vietnam since 2012 and is operator of five offshore Production Sharing Contracts, two of which are held with 100% interest (Block 116 and Block 122) and three are in Joint Venture (Block 114 Eni’s interest 50%, Block 120 - Eni’s interest 66.67%, Block 124 - Eni’s interest 60%).year.

Americas

~~In 2016,~~ Eni’s operations in Americas are conducted mainly in Mexico, United States and Venezuela. In 2019, Eni’s operations in the Americas area accounted for ~~10%~~approximately 6% of its total worldwide production of oil and natural gas.

Ecuador~~Ecuador~~. In 2019, Eni ~~has been present~~divested its activities in ~~Ecuador since 1988. Operations are performed~~the country.

Mexico. In 2019 production start-up was achieved at the operated Area 1 license (Eni’s interest 100%) by means of the drilling of two wells and the installation of a production platform which is linked by a sealine to an onshore treatment unit. The full field development envisages a phased installation of three additional platforms and a FPSO unit, which will increase the production capacity up to 100 KBBL/d in 2021.

In February 2020, exploration activities yielded positive results with the Saasken offshore oil discovery in the operated Block 10 (Eni’s interest ~~100%~~65%) ~~located in the Oriente Basin, in the Amazon forest. In 2016, Eni’s production averaged 11 KBBL/d.~~

~~Exploration and production activities in Ecuador are regulated by a service contract that expires in 2033.~~

~~Block 10 production is processed by a Central Production Facility and transported to the Pacific Coast through a pipeline network.~~

~~In December 2016, development activities of the Villano Phase VI project started up with the drilling of the first of two infilling wells.~~

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~~Mexico.~~ Eni has been present in Mexico since 2015. Eni is operator of the Block 1 (Eni’s interest 100%) to develop the Amoca, Miztón and Tecoalli fields, located in the Gulf of Mexico shallow waters. The delineation campaign of the fields was submitted to the Mexican Authorities in the first quarter of 2016 and plans the drilling of four wells in order to define a fast track and synergic development plan.

~~In January 2017, the delineation campaign started with the first well.~~.

~~Trinidad and Tobago~~. Eni has been present in Trinidad and Tobago since 1970. In 2016, Eni’s production averaged 70 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block, located offshore North of Trinidad.

~~Exploration and production activities in Trinidad and Tobago are regulated by PSAs.~~

Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields. Production is supported by two fixed platforms linked to the Hibiscus processing facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant on Trinidad’s coast and it is sold under long-term contracts with prices linked to the United ~~States, as well as alternative destinations markets.~~

~~United States~~States.~~. Eni has been present in the United States since 1968. Activities are performed in the shallow and deep offshore of the Gulf of Mexico, onshore and offshore in Alaska, and in Texas onshore.~~

~~In 2016, Eni’s oil&gas production was 91 KBOE/d mainly from the Gulf of Mexico and Alaska fields.~~

~~Exploration and production activities in the United States are regulated by concessions.~~

Eni holds interests in 8441 exploration and production blocks in the Gulf of Mexico, of which 4418 are operated by Eni.

~~The main operated fields are Allegheny and Appaloosa (Eni’s interest 100%), Pegasus (Eni’s interest 85%), Longhorn, Devils Towers and Triton (Eni’s interest 75%).~~ Eni also holds interests ~~in Europa (Eni’s interest 32%), Hadrian South (Eni’s interest 30%), Medusa (Eni’s interest 25%), Lucius (Eni’s interest 8.5%), K2 (Eni’s interest 13.4%), Frontrunner (Eni’s interest 37.5%)~~ and ~~Heidelberg (Eni’s interest 12.5%) fields.~~

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During the year, production start-ups were achieved in the Gulf of Mexico at: (i) the Heidelberg field (Eni’s interest 12.5%) in the deep-water Gulf of Mexico, with a production of approximately 3 KBOE/d net to Eni. During 2017 planned development activities will be completed; (ii) the Phase 2 development of Lucius field (Eni’s interest 8.5%) with production ramp-up to 100 KBOE/d (8 KBOE/d net to Eni); and (iii) the Devil’s Tower South-West production well within the development program of the operated Devil’s Tower field, with a production of approximately 2 KBOE/d.

To achieve the highest safety standards of operations, Eni became a member of the HWCG Consortium of Gulf of Mexico operators. The HWGC provides resources, coordination and performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. For further information on this matter, see “Item 3 – Risk factors”.

~~Eni holds interests in 43 exploration and development~~operates 151 blocks in Alaska with ~~interests ranging from 30 to~~ 100%~~; Eni is the operator in 27 of these blocks.~~ working interest.

~~Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) fields with a 2016 overall~~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.

Venezuela. In 2019, Eni’s production of oil and natural gas averaged 38 KBOE/d and accounted for approximately ~~24 KBBL/d.~~

~~In Texas onshore,~~2% of Eni’s total production. Eni’s production comes from the ~~Alliance Area (Eni’s interest 27.5%).~~

~~Venezuela. Eni has been present in Venezuela since 1998. In 2016, Eni’s production averaged 60 KBOE/d.~~

~~Activity is concentrated both offshore (Gulf of Venezuela and Gulf of Paria) and onshore in the Orinoco Oil Belt.~~

Exploration and production of the oil Junin 5 and Corocoro fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP). The Perla gas field is operated by Cardon IV, a joint venture 50%-50% Eni and Repsol.

~~Eni’s production comes from the giant~~ Perla gas field (Eni’s interest 50%), in the Gulf of Venezuela, the Corocoro field (Eni’s interest 26%), in the ~~Gulfo~~Gulf de Paria, and the ~~Junin~~Junín 5 oil field (Eni’s interest 40%), located in the Orinoco Oil Belt.

~~Development~~ Production activities ~~performed in 2016 were: (i)~~have been negatively affected by the ongoing ~~drilling activities at the Junin 5 oil field. The production level at year-end was approximately 18 KBBL/d at 100%. Possible optimization of development program is currently under evaluation;~~distressed financial and ~~(ii) the completion~~political situation of the ~~first development phase at the Perla field. The six wells currently~~Country. For further information on ~~stream are producing approximately 540 mmCF/d at 100%~~this matter, see “Item 3 – Risk factors – Political considerations”. The gas will be mainly used by PDVSA for the domestic market, under the Gas Sales Agreement in place until 2036. The Perla project includes two additional development phases to achieve a production plateau of approximately 1,200 mmCF/d.

Eni is also participating with a 19.5% interest in Petrolera Güiria for oil exploration and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest for gas exploration, both located offshore in the eastern Venezuela.

~~Australia and Oceania~~

Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2016, the area of Australia and Oceania accounted for 1% of Eni’s total worldwide production of oil and natural gas.

~~Australia. Eni has been present in Australia since 2001. In 2016, Eni’s production of oil and natural gas averaged 23 KBOE/d. Activities are focused on conventional and deep offshore fields.~~

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Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs.

The main production blocks in which Eni holds interests are WA-33-L (Eni’s interest 100%) and JPDA 03-13 (Eni’s interest 10.99%). In the appraisal and development phase Eni holds interests in NT/RL8 (Eni’s interest 100%) and NT/RL7 (Eni’s interest 32.5%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA.

Capital expenditures

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

Disclosure pursuant to Section 13(r) of the Exchange Act

The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate.

AsIn 2017, Eni fully recovered the overdue trade receivable owed by Iranian state- owned companies relating to the cost recovery of ~~December 31, 2016, Eni outstanding trade receivables amounted~~past projects due to $278 million towards the National Iranian National Oil Co (NIOC) which were recorded in connection with the settlement agreement recognized in 2015. This amount was curtailed from the amount outstanding at December 31, 2015 ($339 million). The State counterparties expressed their willingness to negotiate a repayment plan of overdue receivables based on arrangements relating the sale of volumesenactment of the ~~Iranian counterpart equity crude and the attribution to Eni of a percentage of the sale proceeds. This agreement has been enacted~~agreements signed in the last months of 2016 with a reimbursement to Eni of $44 million. Negotiations are underway to identify additional crude volumes to be marketed, some of which have already been awarded to Eni in early 2017, with the aim of fully recovering the overdue amounts. Eni had2016. There were no ~~payables~~more outstanding receivables towards ~~NIOC~~Iran’s national oil companies as of December 31, ~~2016.~~2019. In 2019, Eni made payments in the region of $1$0.04 million to the Iranian Social Security Organization in connection to health and social security insurance for which Eni retains at ~~the balance sheet date~~December 31, 2019 a residual payable amounting to ~~$10~~approximately $5 million, ~~date,~~ which will be settled upon ~~termination~~de-registration of our ~~presence in the country.~~local branch.

Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply/marketing and trading. This segment also includes the activities of electricity generation. In ~~2016,~~2019, Eni’s worldwide sales of natural gas amounted to ~~88.93 BCM, including 2.62 BCM of gas sales made directly by Eni’s Exploration & Production segment.~~73.07 BCM. Sales in Italy amounted to ~~38.43~~37.85 BCM, while sales in European markets were ~~42.43~~27.07 BCM that included 4.37 BCM of gas sold to certain importers to Italy.

~~In the Gas & Power segment we expect a continuing weak outlook for natural gas sales~~The business results of operations in 2019 and ~~prices due to structural headwinds~~its strategy are described in ~~the industry as we forecast oversupplies~~“Item 5 – Group results of operations” and ~~strong competition across all~~“Item 5 – Management’s expectations of ~~our main markets in Europe, including Italy.~~operations.”

Supply of natural gas

In ~~2016,~~2019, Eni’s ~~consolidated subsidiaries supplied 82.64 BCM~~total supply of natural gas was 70.65 BCM, down by ~~2.75~~3.50 BCM, or ~~3.2%~~4.7% from ~~2015.~~2018. Gas volumes supplied outside Italy ~~(76.64~~(65.21 BCM from consolidated companies), imported

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in Italy or sold outside Italy, represented approximately ~~93%~~92% of total supplies, down by ~~2.02~~3.61 BCM, or ~~2.6%~~5.2% compared to the previous year, due to lower volumes purchased in ~~Libia~~Algeria (down ~~2.38~~by 5.36 BCM), in Russia (down ~~2.34~~by 1.53 BCM), in Indonesia (down by 1.48 BCM), partially offset by higher purchases in France (up by 2.90 BCM), in Libya (up by 1.31 BCM) and in the ~~Netherlands (down 2.13~~United States (up by 1.20 BCM)~~, partly offset by higher volumes purchased in Algeria (up 6.85 BCM)~~.

Supplies in Italy ~~(6.00~~(5.44 BCM) ~~decreased~~increased by 2.1% from ~~2015 (down 0.73 BCM or 10.8%) due to the production shutdown in the Val d’Agri district during the period April-August 2016.~~ 2018.

In ~~2016,~~2019, main gas volumes from equity production derived from: (i) Italian gas fields ~~(4.5 BCM)~~(3.4 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea ~~(2.2 BCM)~~(2.3 bcm); (iii) Libyan fields ~~(1.5 BCM)~~(1.8 bcm); (iv) Indonesia (0.8 bcm) and (v) the United States ~~(1.4 BCM); and (v) other European areas~~ (0.2 ~~BCM)~~bcm).

~~Considering also direct sales of the Exploration & Production segment and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied~~ Supplied gas volumes from equity production were approximately ~~15.02 BCM~~8.5 bcm representing ~~17%~~12% of total volumes available for sale.

The available for sale by Eni’s affiliates amounted to 2.56 bcm (down by 3.8% compared to 2018) and mainly referred to supplied volumes from Oman, Spain, the United States and Nigeria.

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


Natural gas supply	2014		2015		2016		2019		2018		2017
	(BCM)						(BCM)
Italy		6.92		6.73		6.00		5.44		5.33		5.05
Outside Italy		75.99		78.66		76.64		65.21		68.82		73.23
Russia		26.68		30.33		27.99		24.71		26.24		28.09
Algeria (including LNG)		7.51		6.05		12.90		6.66		12.02		13.18
Libya		6.66		7.25		4.87		5.86		4.55		4.76
the Netherlands		13.46		11.73		9.60		4.12		3.95		5.20
Norway		8.43		8.40		8.18		6.43		6.75		7.48
the United Kingdom		2.64		2.35		2.08		1.75		2.21		2.36
Hungary		0.38		0.21		0.02
Indonesia (LNG)								1.58		3.06		0.74
Qatar (LNG)		2.98		3.11		3.28		2.79		2.56		2.36
Other supplies of natural gas		5.56		7.21		5.81		7.91		5.52		6.75
Other supplies of LNG		1.69		2.02		1.91		3.40		1.96		2.31
Total supplies of subsidiaries		82.91		85.39		82.64		70.65		74.15		78.28
Withdrawals from (input to) storage		(0.20)				1.40		0.08		0.08		0.31
Network losses, measurement differences and other changes		(0.25)		(0.34)		(0.21)		(0.22)		(0.18)		(0.45)
Volumes available for sale of Eni’s subsidiaries		82.46		85.05		83.83		70.51		74.05		78.14
Volumes available for sale of Eni’s affiliates		3.65		2.67		2.48		2.56		2.66		2.69
E&P volumes		3.06		3.16		2.62
Total volumes available for sale		89.17		90.88		88.93		73.07		76.71		80.83

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 ~~2016,~~2019, natural gas sales amounted to ~~88.93~~73.07 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted ~~entities and upstream sales in Europe and in the Gulf of Mexico)~~entities), representing a decrease of ~~1.95~~3.64 BCM, or ~~2.1%~~4.7% from the previous year. Sales in Italy ~~were barely unchanged (38.43~~(37.85 BCM)~~; lower volumes in the wholesale~~ decreased by 3% from 2018. Lower sales to wholesalers, spot market and residential segment were partly offset by higher ~~spot volumes.~~sales to thermoelectrical and industrial segments. Sales in the European markets ~~were 38.06~~amounted to 22.70 BCM, ~~down by 0.6%~~a decrease of 12.7% or 3.30 BCM from ~~2015.~~

Direct sales of Exploration & Production segment in Europe and the Gulf of Mexico (2.62 BCM) decreased by 0.54 BCM due to lower volumes marketed in the United Kingdom and the United States, partially offset by higher sales in Norway.2018.

Sales to long-term buyers were ~~down~~4.37 BCM; up by ~~5.2%~~27.8% compared to the previous year ~~due~~thanks to ~~shorter~~the higher availability of Libyan ~~output as well as lower sales to~~output.

Sales in the Extra European markets ~~(down~~(8.15 BCM) decreased by ~~14.7%) driven by~~0.11 BCM or 1.3% due to lower LNG ~~volumes marketed~~sales in the Far East ~~due to~~markets, partly offset by higher volumes sold in the ~~lack of contracts renewal.~~United States.

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

Natural gas sales by entities 2014 2015 2016
(BCM)
Total sales of subsidiaries 81.73 84.94 83.34
Italy (including own consumption) 34.04 38.44 38.43
Rest of Europe 43.07 41.14 40.52
Outside Europe 4.62 5.36 4.39
Total sales of Eni’s affiliates (Eni’s share) 4.38 2.78 2.97
Italy
Rest of Europe 3.15 1.75 1.91
Outside Europe 1.23 1.03 1.06
Total sales of G&P 86.11 87.72 86.31
E&P in Europe and in the Gulf of Mexico(a)
3.06 3.16 2.62
Worldwide gas sales 89.17 90.88 88.93

~~(a)~~

E&P sales include volumes marketed by the Exploration & Production segment in Europe (2.60, 2.75 and 2.32 BCM in 2014, 2015 and 2016, respectively) and in the Gulf of Mexico (0.46, 0.41 BCM and 0.30 in 2014, 2015 and 2016, respectively).

Natural gas sales by market 2014 2015 2016
(BCM)
ITALY 34.04 38.44 38.43
Wholesalers 4.05 4.19 3.83
Italian gas exchange and spot markets 11.96 16.35 17.08
Industries 4.93 4.66 4.54
Medium-sized enterprises and services 1.60 1.58 1.72
Power generation 1.42 0.88 0.77
Residential 4.46 4.90 4.39
Own consumption 5.62 5.88 6.10
INTERNATIONAL SALES 55.13 52.44 50.50
Rest of Europe 46.22 42.89 42.43
Importers in Italy 4.01 4.61 4.37
European markets 42.21 38.28 38.06
Iberian Peninsula 5.31 5.40 5.28
Germany/Austria 7.44 5.82 7.81
Benelux 10.36 7.94 7.03
Hungary 1.55 1.58 0.93
United Kingdom/Northern Europe 2.94 1.96 2.01
Turkey 7.12 7.76 6.55
France 7.05 7.11 7.42
Other 0.44 0.71 1.03
Extra European markets 5.85 6.39 5.45
E&P in Europe and in the Gulf of Mexico 3.06 3.16 2.62
WORLDWIDE GAS SALES 89.17 90.88 88.93

~~European markets~~

~~A review of Eni’s presence in the key European markets is presented below.~~


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


Natural gas sales by market	2019		2018		2017
	(BCM)
ITALY		37.85		39.03		37.43
Wholesalers		7.79		9.15		8.36
Italian gas exchange and spot markets		12.13		12.49		10.81
Industries		4.92		4.79		4.42
Medium-sized enterprises and services		0.87		0.79		0.93
Power generation		1.90		1.50		2.22
Residential		3.99		4.20		4.51
Own consumption		6.25		6.11		6.18
INTERNATIONAL SALES		35.22		37.68		43.40
Rest of Europe		27.07		29.42		38.23
Importers in Italy		4.37		3.42		3.89
European markets		22.70		26.00		34.34
Iberian Peninsula		4.22		4.65		5.06
Germany/Austria		2.10		1.83		6.95
Benelux		3.77		5.29		5.06
United Kingdom/Northern Europe		1.75		2.22		2.21
Turkey		5.56		6.53		8.03
France		4.48		4.95		6.38
Other		0.82		0.53		0.65
Extra European markets		8.15		8.26		5.17
WORLDWIDE GAS SALES		73.07		76.71		80.83

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~~Benelux~~. Eni holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, through the Belgium Gas & Power branch, and its significant exposure to spot markets in Western Europe. Furthermore Eni operates in the retail and middle market through its subsidiary. In 2016, sales in Benelux amounted to 7.03 BCM (7.94 BCM in 2015), down by 0.91 BCM, or 11.5%.

~~France~~. Eni sells natural gas to industrial clients and wholesalers, as well as to the segments of retail and middle market. Eni is present in the French market through its direct commercial activities and through its subsidiary. In 2016, sales in France amounted to 7.42 BCM (7.11 BCM in 2015), an increase of 0.31 BCM, or 4.4%, from a year ago.

~~Germany-Austria~~. Eni operates in Germany-Austria through its direct commercial activities and through its subsidiaries. In 2016, total sales in Germany-Austria amounted to 7.81 BCM, an increase of 1.99 BCM, or 34.2%.

The LNG business

Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from, Qatar, Nigeria, ~~Oman~~Indonesia and ~~Algeria.~~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. ~~In 2017, the G&P LNG business will start marketing volumes of gas produced at the E&P large Jangkrik gas complex, off Indonesia.~~ Final markets of that gas include ~~the Chinese market~~Europe, China, Pakistan and ~~other areas.~~Japan. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities.

LNG sales 2014 2015 2016
(BCM)
G&P sales 8.9 9.0 8.1
Rest of Europe 5.0 4.8 5.2
Extra European markets 3.9 4.2 2.9
E&P sales 4.4 4.5 4.3
Liquefaction plants:
- Soyo (Angola) 0.1 0.1
- Bontang (Indonesia) 0.5 0.5 0.4
- Point Fortin (Trinidad & Tobago) 0.6 0.7 0.7
- Bonny (Nigeria) 2.8 2.8 2.6
- Darwin (Australia) 0.4 0.5 0.5
13.3 13.5 12.4


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 ~~to large industrial users,~~business located in urban area, the Company has ~~been developing~~developed a commercial offer that provides the combined supply of gas and power to the retail market in Italy and ~~fuels.~~in France.

In ~~2016,~~2019, power sales ~~(37.05~~(39.49 TWh) were directed to the free market ~~(74%~~(72%), the Italian Power Exchange ~~(15%~~(18%), industrial sites (9%) and others ~~(2%~~(1%). Compared to ~~2015,~~2018, electricity sales in the free market were up by ~~6.2%~~2.40 TWh or by 9.3%, due to higher volumes sold to wholesalers, ~~and~~ middle market and retail segments, partially offset by lower volumes ~~traded~~sold to ~~small and medium size enterprises and~~the large ~~clients.~~customers.

~~TABLE OF CONTENTS~~


Power availability	2014		2015		2016
Power availability							2019		2018		2017
	(TWh)						(TWh)
Power generation sold		19.55		20.69		21.78		21.66		21.62		22.42
Trading of electricity (a)		14.03		14.19		15.27		17.83		15.45		12.91
		33.58		34.88		37.05		39.49		37.07		35.33
Power sales by market
Free market (a)		24.86		25.90		27.49		28.31		25.91		26.53
Italian Exchange for electricity		4.71		5.09		5.64		7.27		7.17		5.21
Industrial plants		3.17		3.23		3.11		3.38		3.49		3.01
Other (a)		0.84		0.66		0.81		0.53		0.50		0.58
		33.58		34.88		37.05		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 ~~2016,~~2019, power generation was ~~21.78~~21.66 TWh, ~~up by 1.09 TWh, or 5.3% from 2015, mainly due to higher production at Brindisi, Ferrara, Ferrera Erbognone and Ravenna plants following increasing demand.~~substantially in line with 2018. As of December 31, ~~2016,~~2019, installed operational capacity was 4.7 GW, ~~(4.9 GW as of~~unchanged compared to December 31, ~~2015).~~ 2018.

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Electricity trading (17.83 TWh) reported an increase of 15.4% thanks to ~~15.27 TWh, due to higher purchases on the spot market (up 7.6%) reflecting~~ the optimization of inflows and outflows of power.

Site

Total installed
capacity
in ~~2016~~2019
(GW)

Technology

Fuel

Brindisi

1.3

CCGT

gas

Ferrera Erbognone

1.0

CCGT

gas/syngas

~~Livorno~~ ~~(a)~~

~~Power station~~

~~gas/fuel oil~~

Mantova

~~0.8~~0.9

CCGT

gas

Ravenna

1.0

CCGT

gas

Ferrara~~(b)~~(a)

0.4

CCGT

gas

Bolgiano

0.1

Power station

gas

4.7

(a)

~~Since March 1, 2016 Livorno was tranferred to R&M segment.~~

~~(b)~~

Eni’s share of capacity.

Power generation 2014 2015 2016
Purchases
Natural gas (mmCM) 4,074 4,270 4,334
Other fuels (ktoe) 338 313 360
- of which steam cracking 104 87 105
Production
Electricity (TWh) 19.55 20.69 21.78
Steam (ktonnes) 9,010 9,318 7,974
Installed generation capacity (GW) 4.9 4.9 4.7

~~TABLE OF CONTENTS~~


Power generation		2019		2018		2017
Purchases
Natural gas	(mmCM)		4,410		4,300		4,359
Other fuels	(ktoe)		276		356		392
- of which steam cracking			91		94		104
Production
Electricity	(TWh)		21.66		21.62		22.42
Steam	(ktonnes)		7,646		7,919		7,551
Installed generation capacity	(GW)		4.7		4.7		4.7

International transport

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

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

International Transport infrastructure Route

Lines Total length Diameter
Transport
capacity(1)

Transit
capacity(2)
Compression
stations
(units) (km) (inch) (BCM/y) (BCM/y) (No.)
TTPC (Oued Saf Saf-Cap Bon) 2 lines of km 370 740 48 34.3 33.2 5
TMPC (Cap Bon-Mazara del Vallo) 5 lines of 155 775 20/26 33.5 33.5
GreenStream (Mellitah-Gela) 1 line of km 520 520 32 8.0 8.0 1
Blue Stream (Beregovaya-Samsun) 2 lines of km 387 774 24 16.0 16.0 1

~~(1)~~

~~Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.~~

~~(2)~~

~~The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.~~

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

International transport activities

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

The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each ~~155-kilometer~~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 GreenStream pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is ~~520-kilometer~~520-kilometers long with a transport capacity of 8 BCM/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system.

Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.

Capital expenditures

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

Refining & Marketing & Chemicals

Refining & Marketing

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

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

67The business results depend heavily on trends in refining margins, i.e. the spread between the cost of the oil feedstock and the price of the refined products obtained from the crude processing.

~~TABLE OF CONTENTS~~

In ~~2016~~2019 refining margins in the Mediterranean area ~~decreased~~increased by approximately ~~50%~~16% y-o-y ~~due~~ to ~~a high level of inventories of gasoline and gasoil because of a high utilization rate of refineries as well as availability~~4.3 $/BBL driven by the higher relative prices of products ~~coming from~~compared to the ~~Middle East. Looking forward, management~~cost of the petroleum feedstock. Notwithstanding this trend, the refining business was negatively affected by the appreciation of crudes against the Brent and a less favourable products scenario. Management believes that refining margins will remain under pressure in the ~~medium~~short-to-medium term ~~will remain stable on~~due to continuing competition. In the ~~2016 level; in the longer term, margins will improve~~medium-term, spreads between products and crude may find a support as a ~~result~~consequence of the IMO 2020 ~~IMO legislation,~~regulations, which will lead, among other solutions, to the substitution of bunker fuel oil with cleaner fuels (gasoil, ULSFO and LNG). that could be short in the first period of law application, with benefit for high conversion refineries. In ~~marketing, competition remains tough,~~the longer term, refinery margins will normalize, as a result of supply-demand re-alignment thanks investments by both refining companies (fuel oil destruction units) as well as ship-owners (scrubbers, retrofitting, new ships/engines).

The business results of operations in ~~particular from unbranded~~2019 and ~~large retailers.~~its strategy are described in “Item 5 �� Group results of operations” and “Item 5 – Management’s expectations of operations”.

Supply

In ~~2016,~~2019, a total of ~~23.35~~23.43 mmtonnes of crude were purchased (compared with ~~24.80~~22.62 mmtonnes in ~~2015)~~2018), of which ~~3.43~~4.24 mmtonnes by equity crude oil. The breakdown by geographic area was the following: approximately ~~43%~~24% of purchased crude came from ~~Russian Commonwealth, 30% from~~ the Middle East, ~~12%~~23% from Russia, 17% from Central Asia, 13% from Italy, ~~11%~~13% from North Africa, 1%2% from West Africa, 1%2% from North Sea and 2%6% from other areas.

Refining

In ~~2016,~~2019, Eni refinery capacity (balanced with conversion capacity) was approximately ~~27.4~~36.6 mmtonnes (equal to ~~548~~732 KBBL/d), with a conversion index of ~~50%~~56%. Conversion index is a measure of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able

TABLE OF CONTENTS

to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 KBBL/d), with a ~~49%~~55% conversion index. In ~~2016,~~2019, Eni’s refineries throughputs in Italy and outside Italy were ~~24.52~~22.74 mmtonnes. The refinery utilization rate, ratio between throughputs and refinery capacity, is 88%.

Refining system in ~~2016~~2019

	Ownership (%)		Balanced refining capacity (Eni’s share) (KBBL/d)		Utilization rate (Eni’s share) (KBBL/d)		Conversion index(1) (%)		Fluid catalytic cracking (FCC)(2) (KBBL/d)		Residue conversion(2) (KBBL/d)		Hydro- cracking(2) (KBBL/d)		Visbreaking/ Thermal Cracking(2) (KBBL/d)		Ownership (%)		Balanced refining capacity (Eni’s share) (KBBL/d)		Utilization rate (Eni’s share)(1) (%)		Conversion index(2) (%)
Wholly-owned refineries				388		90		49		34		16		90		29				388		89		55
Italy
Sannazzaro		100		200		98		71		34		16		51		29		100		200		85		74
Taranto		100		104		73		38				0		39		0		100		104		89		56
Livorno		100		84		91		11										100		84		98		11
Partially owned refineries				160		93		52		143		25		75		27				344		84		57
Italy
Milazzo		50		100		90		60		45		25		32				50		100		94		60
Germany
Vohburg/Neustadt (Bayernoil)		20		41		96		36		49								20		41		60		36
Schwedt		8.33		19		100		42		49				43		27		8.33		19		87		42
UAE
ADNOC Refining																		20		184				63
Total				548		90		50		177		41		165		56				732		88		56

(1)

Since the participation interest in ADNOC Refining has been acquired effective August 1, 2019, the utilization rate has been calculated only for refineries owned or participated for the full year.

(2)

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

~~(2)~~

~~Conversion unit capacities are 100%~~.

Italy

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

The Sannazzaro refinery has a balanced capacity of 200 KBBL/d and a conversion index of ~~71%~~74%. Located in the Po Valley, in the center of the Northern Italy, Sannazzaro is one of the most efficient

~~TABLE OF CONTENTS~~

refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.

The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of ~~38%~~56%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni ~~60.77%~~61%) through a pipeline. The main equipments are a topping-vacuum unit, a hydrocracking, a platforming unit and two desulphurization units.

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

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The Milazzo refinery (Eni 50%) has a balanced capacity of 200 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipments in the refinery are: two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracker (HdC), one reforming unit and one LC fining (ebullated bed residue conversion).

Outside Italy

In Germany, Eni owns an interest of 8.33% stake in the Schwedt refinery (PCK) and an interest of 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni’s refining capacity in Germany is 60 KBBL/d to supply Eni’s distribution network in the country.

~~Green~~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.

Ownership
share
(%)

Capacity
(2016)
(ktonnes/y)

Capacity
(at regime)
(ktonnes/y)

Throughput
(2016)
(ktonnes/y)

Wholly-owned
Venezia 100 360 560 212
Gela 100 750
Total green refineries 360 1,310 212

~~Green Refining~~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

Eni fully owns ~~the green refinery of~~two biorefineries in Italy, specifically in Venice and ~~the site of Gela, where another green refinery will be realized.~~Gela.

The Venice ~~green refinery entered into~~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/~~y. The refinery exploits~~y, leverages on the EcofiningTMproprietary ~~EcofiningTM~~ technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At ~~regime,~~full capacity, the refinery production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing ~~the CO2 emission.~~CO2 emissions.

The Gela refinery is located onin the Southern coast of Sicily. The refinery was shut-down in March 2014 ~~and in November 2014, Eni signed a Memorandum of Understanding~~ for the reconversion 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 EcofiningTM technology, developed and licensed by Eni, to convert into biodiesel, vegetable oil and second generation raw materials, such as used cooking oil and animal fat. The plant properties allow the production of biodiesel in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain, deploying the full capacity in process second-generation feedstock.

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into a bio-refinery with the Ministry for Economic Development and Local Authorities. In 2016 Eni’s activities continued in line with the commitments foreseen in the Memorandum of Understanding. In April 2016 Eni began the construction activities at the Green Refinery project. The refinery will have a capacity of 750 ktonnes/y. The conversion will leverage on the application of ecofining proprietary technology, developed and patented by Eni, to convert unconventional and second generation raw materials into green diesel, a highly sustainable biofuel.

~~Gela reconversion represents the first integrated and cross businesses’ project which Eni is developing in Italy to combine the needs of the business and those of the communities living in the area.~~

~~The agreement foresees also:~~

•

~~the launch of new hydrocarbon exploration and production activities in the Region of Sicily and the offshore area;~~

•

~~the realization of a modern hub for shipping locally produced crude oil and green fuel produced on the site;~~

•

a feasibility study, to identify LNG and CNG storage and transport infrastructure in Gela, as well as the realization of a project for the production of natural latex from natural products with the relative development of the agricultural supply chain;

•

~~the set-up of a competence center focused on safety issues;~~

•

~~a plan for the environmental remediation of plants and areas that will gradually lose their industrial destination.~~

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


Availability of refined products	2014		2015		2016
Availability of refined products
							2019		2018		2017
	(mmtonnes)						(mmtonnes)
ITALY
Refinery throughputs
At wholly-owned refineries		16.24		18.37		17.37		17.26		16.78		16.03
Less input on account of third parties		(0.58)		(0.38)		(0.27)		(1.25)		(1.03)		(0.34)
At affiliated refineries		4.26		4.73		4.51		4.69		4.93		5.46
Refinery throughputs on own account		19.92		22.72		21.61		20.70		20.68		21.15
Consumption and losses		(1.33)		(1.52)		(1.53)		(1.38)		(1.38)		(1.36)
Products available for sale		18.59		21.20		20.08		19.32		19.30		19.79
Purchases of refined products and change in inventories		7.19		6.22		6.28		7.27		7.50		6.74
Products transferred to operations outside Italy		(0.72)		(0.48)		(0.39)		(0.68)		(0.54)		(0.46)
Consumption for power generation		(0.57)		(0.41)		(0.37)		(0.35)		(0.35)		(0.34)
Sales of products		24.49		26.53		25.60		25.56		25.91		25.73
Biorefinery throughputs								0.31		0.25		0.24
OUTSIDE ITALY
Refinery throughputs on own account		5.11		3.69		2.91		2.04		2.55		2.87
Consumption and losses		(0.21)		(0.23)		(0.22)		(0.18)		(0.20)		(0.22)
Products available for sale		4.90		3.46		2.69		1.86		2.35		2.65
Purchases of finished products and change in inventories		4.48		4.77		4.72		4.17		4.12		4.36
Products transferred from Italian operations		0.72		0.48		0.40		0.68		0.54		0.46
Sales of products		10.10		8.71		7.81		6.71		7.01		7.47
Refinery throughputs on own account		25.03		26.41		24.52		22.74		23.23		24.02
of which: refinery throughputs of equity crude on own account		5.81		5.04		3.43		4.24		4.14		3.51
Total sales of refined products		34.59		35.24		33.41		32.27		32.92		33.20
Crude oil sales		0.33		0.27		0.20		0.44		0.28		0.86
TOTAL SALES		34.92		35.51		33.61		32.71		33.20		34.06

In ~~2016,~~2019, Eni’s refining throughputs on own account in Europe were ~~24.52~~22.74 mmtonnes, ~~down~~slightly decreased by ~~7.2 %~~2.1% from ~~2015~~2018, due toto: the lower ~~availability of domestic crude oil driven by~~throughputs at the ~~shutdown~~Bayernoil refinery, as a result of the ~~Val d’Agri field~~unavailability of the Vohburg facility in the early nine months of the year following the event occurred in September 2018, the adverse climatic events at the ~~Taranto plant during the period of April - August 2016,~~Milazzo refinery, as well as ~~other planned maintenance turnarounds (Livorno and Milazzo),~~the participated PCK refinery, affected by the Druzhba pipeline contamination. These negatives were partially offset by higher volumes processed by the Taranto refinery following lower maintenance standstills.

In Italy, the refinery throughputs (20.70 mmtonnes) were in line with 2018; the lower volumes processed at ~~Sannazzaro despite~~refineries affected by higher maintenance standstills, logistic issues due to adverse climatic events and the ~~incident occurred in December 2016. On a homogeneous basis, when excluding~~upset at the ~~impact of~~Milazzo refinery, as well as the ~~disposal of CRC~~lower throughputs at the Livorno refinery ~~in Czech Republic finalized~~to counteract the scenario, were offset by higher volumes processed at the Taranto refinery leveraging on ~~April 30, 2015, refining throughputs reported a decrease of 4.5% compared to the 2015.~~fewer shutdowns.

~~TABLE OF CONTENTS~~

Outside Italy, Eni’s refining throughputs on own account were ~~2.91~~2.04 mmtonnes, down by ~~0.78 mmtonnes~~approximately 510 ktonnes or ~~21.1% from previous year, mainly~~20% due to the ~~above-mentioned divestment in~~above mentioned downtime of the ~~Czech Republic finalized in the second quarter of 2015.~~

Bayernoil refinery. Total throughputs in wholly-owned refineries were ~~17.37~~17.26 mmtonnes, ~~down~~up by ~~1 mmtonne,~~0.48 mmtonnes or ~~5.4%~~2.9% compared with ~~2015, determining a~~2018.

The refinery utilization rate, ~~(ratio~~ratio between throughputs and ~~balanced capacity) of 89.5%~~refinery capacity, is 88%.

Approximately ~~14.8%~~18.9% of processed crude was ~~equity, down~~supplied by ~~approximately 6 percentage points~~Eni’s Exploration & Production segment, increasing by 18.3% from ~~2015 (20.4%).~~2018.

The volumes of biofuels produced from vegetable oil increased by 22.9% compared to 2018, driven by the start-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.

Logistics

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

~~It owns an integrated infrastructure consisting of 17 directly managed depots and a network of oil~~

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Oil and refined products pipelines. Eni logistic model is organized in three hubs (North, Central and South Italy). These hubs manage the product flows in order to guarantee high safety and technical standards, as well as cost effectiveness. Eni is also in joint venture with other Italian operators to optimize its logistic footprint and increase efficiency. Other depots are operated by seven different joint ventures (Sigemi, Petrolig, Petroven, Petra, Seram, Disma, Toscopetrol). Since the beginning of 2017 Petrolig joint venture ends. Eni transports oil and refined products:transported: (i) by sea through spot and long-term contracts of tanker ships; and (ii) inland through a proprietary pipeline and depots network directly operated.

In particular, Eni owns and operates an integrated infrastructure consisting of 16 directly managed depots and a network of oil and refined products pipelines extending approximately ~~1,462~~1.154 kilometers. Eni 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 5 different logistic joint ventures (Sigemi, Seram, Disma, Seapad, Toscopetrol), together with other Italian operators, that operate other localized depots and pipelines.

Secondary distribution to retail and wholesale markets is outsourced to independent ~~tanker carriers.~~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	2014		2015			2016		2019		2018		2017
	(mmtonnes)							(mmtonnes)
Italy
Retail		6.14		5.96			5.93		5.81		5.91		6.01
Wholesale		7.57		7.84			8.16		7.68		7.54		7.64
		13.71		13.8			14.09		13.49		13.45		13.65
Petrochemicals		0.89		1.17			1.02		0.83		0.96		0.86
Other sales		9.89		11.56			10.49		11.24		11.5		11.22
Total		24.49		26.53			25.6		25.56		25.91		25.73
Outside Italy
Retail		3.07		2.93			2.66		2.44		2.48		2.53
Wholesale		5.03		4.25			3.61		3.11		3.29		3.48
		8.10		7.18			6.27		5.55		5.77		6.01
Other sales		2.00		1.53			1.54		1.16		1.24		1.46
Total		10.1		8.71			7.81		6.71		7.01		7.47
TOTAL SALES		34.59		35.24	��		33.41		32.27		32.92		33.20

In ~~2016,~~2019, retail sales ~~volumes~~ of refined products ~~(33.41~~(32.27 mmtonnes) were down by ~~1.83~~0.65 mmtonnes or by ~~5.2%~~2% from ~~2015,~~2018, mainly due to the ~~assets disposal~~decrease of sales to oil companies and petrochemical industry in Italy and lower volumes marketed in the ~~Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungary~~wholesalers segment in the ~~second half~~rest of ~~2016.~~Europe.

Retail sales in Italy

In 2019, retail sales in Italy were 5.81 mmtonnes, with a decrease compared to 2018 (about 100 ktonnes from 2018 or down by 1.7%). Retail sales in the premium segment increased significantly. Average gasoline and gasoil throughput (1,586 kliters) was substantially in line with 2018. Eni’s retail market share of 2019 was 23.7%, slightly down from 2018 (24%). As of December 31, 2019, Eni’s retail network in Italy consisted of 4,184 service stations, lower by 39 units from December 31, 2018 (4,223 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (34 units), closure of low throughput stations (6 units), partly offset by the net increase of 1 motorway concession.

Retail sales in the Rest of Europe

Retail sales in the Rest of Europe were 2.44 mmtonnes, recording a slight reduction from 2018 (down by 1.6%) mainly due to lower volumes traded in Germany, following the production unavailability at the Bayernoil plant and in France.

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~~Retail sales in Italy~~

In 2016, retail sales in Italy were 5.93 mmtonnes, with a decrease compared to 2015 (about 30 ktonnes from 2015 or 0.5%) due to a reduction of sales in Eni highway segment, partially offset by an increase in owned stations. Average gasoline and gasoil throughput (1.551 kliters) decreased by approximately 20 kliters from 2015. Eni’s retail market share in 2016 was 24.3%, down by 0.2 percentage points from 2015 (24.5%).

As of December 31, 2016, Eni’s retail network in Italy consisted of 4,396 service stations, lower by 24 units from December 31, 2015 (4,420 service stations), resulting from the release of low throughput stations (27 units), offset by positive balance of acquisitions/releases of lease concessions (3 units).

~~Retail sales in the rest of Europe~~

Eni’s strategy in the rest of Europe is focused on selectively growing its presence, particularly in Germany and Austria leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities.

In 2016, retail sales of refined products in the rest of Europe (2.66 mmtonnes), recorded a reduction from 2015 (down by 9.2%). This result reflected mainly the assets disposal in the Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungary in the second half of 2016. These negatives were partially offset by higher volumes traded in France, Austria and Germany. On a homogeneous basis, when excluding the impact of the assets disposal in Eastern Europe, sales increased by 1%.

At December 31, ~~2016,~~2019, Eni’s retail network in the Rest of Europe consisted of ~~1,226~~1,227 units, ~~decreasing~~increasing by ~~200~~2 units from December 31, ~~2015, due to the service stations disposal above mentioned.~~2018, mainly in Germany. Average throughput ~~(2,340~~(2,356 kliters) ~~increased~~decreased by 6835 kliters compared to ~~2015 (2,272~~2018 (2,391 kliters).

Other businesses

Wholesale

Eni is strongly present in wholesale market in Italy, including sales of diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels 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 isare supported by a widespread commercial and logistical organization presence throughout Italy and is articulated in local marketing offices and a network of agents and concessionaires.

In ~~2016,~~2019, sales volumes on wholesale markets in Italy ~~(8.16~~(7.68 mmtonnes) increased by ~~0.32 mmtonnes or 4.1%~~1.9% from ~~the previous year,~~2018, mainly due to higher volumes marketed of ~~jet fuel,~~ gasoil, bitumen and ~~fuel oil partly~~gasoline offset by lower sales of ~~bunkering.~~jet fuel and bunkers.

Wholesale sales in the Rest of Europe were ~~3.18~~2.63 mmtonnes, down by ~~17%~~6.7% from ~~2015~~2018 due to lower sold volumes in Germany due to the ~~above-mentioned asset disposals. On a homogeneous basis, sales are barely unchanged from 2015.~~ unavailability of the Bayernoil refinery and France, partly offset by higher volumes in Switzerland, Spain and Austria.

Supplies of feedstock to the petrochemical industry ~~(1.02~~(0.83 mmtonnes) decreased by ~~12.8%~~13.5%. Other sales in Italy and outside Italy ~~(12.03~~(12.40 mmtonnes) decreased by ~~approximately 1.05~~0.34 mmtonnes or 8%down by 2.7%, mainly due to lower ~~sales~~ 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 ~~five~~four bottling plants, 1 owned storage site and coastal storage sites located in Livorno, Naples and Ravenna.

LPG is used as heating and automotive fuel. In ~~2016,~~2019, Eni share of LPG market in Italy was ~~17.5%~~16.95%.

~~TABLE OF CONTENTS~~

Outside Italy, the main market of Eni is Ecuador, with a market share of ~~38%~~37.3%.

Lubricants

Eni operates ~~six~~five (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, ~~USA,~~ 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 ~~2016,~~2019, Eni’s share of lubricants market in Italy was ~~21%~~19.85%, in Europe 3% and on a worldwide base ~~0,6%~~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 10.9 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About ~~80%~~70% 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 ~~20%~~30% is purchased.

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Chemicals

Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production ~~sites~~hubs are located in Italy and Western Europe. ~~These~~

The business results of operations in 2019 and its strategy are ~~predominantly oil-based businesses with a history~~described in “Item 5 – Group results of ~~losses~~operations” and ~~poor growth prospects. In fact, we face structural headwinds in our legacy basic petrochemicals and plastics businesses due to the commoditized nature~~“Item 5 – Management’s expectations of our products, low entry barriers, lack of scale, exposure to the volatility in the costs of oil-based feedstock, cyclicality in demand, and strong competitive pressures from operators with lower cost structure especially from the Middle and Far East and other weaknesses. Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. See “Item 3 – Risk factors”operations”.

In ~~2016~~2019 sales of chemical products amounted to ~~3,759~~4,285 ktonnes, decreased from ~~2015~~2018 (down by 42653 ktonnes, or ~~1.1%~~13.2%) mainly in ethylene, olefins and derivatives.

Average sale prices of the intermediates business decreased by 9.9% from 2018, with derivatives and olefins down by 10.6% and 10.2%, respectively. The polymers reported a decrease of 10.8% from 2018.

Petrochemical production of 8,068 ktonnes decreased by 1.42 mmtonnes (down by 14.9%) mainly due to ~~the stagnation~~lower production of ~~demand in Europe. The declines were registered in polyethylene~~intermediates business (down by ~~9.8%~~18.4%), in particular aromatics and ~~styrene (down by 9.1%) following~~olefins; the ~~shutdown of Ragusa and Mantova, partly offset by higher volumes in derivatives among intermediates (up by 14.8%) and elastomers (up by 6.7%), driven by demand increase in the Tyre sector.~~

~~Petrochemical~~polymers production of ~~5,646~~2,250 ktonnes decreased by ~~54 ktonnes (down~~4.4% with elastomers, polyethylene and styrenics down by ~~0.9%). Higher decreases occurred in polyethylene (down by 8.6%) due to a weak demand~~7.0%, 3.9% and in styrene (down by 7.2%) due to planned and unplanned Mantova standstills. Derivatives productions increased (up by 10.2%) as well as elastomers (up by 7.1%) due to the recovery in sales volumes from the lower levels registered in 2015. 3.8%, respectively.

The main decreases in production were registered at the ~~Ragusa~~Priolo site (down by ~~45%~~23.3%), due to ~~a malfunctioning~~the event occurred at the ~~plant, as well as Ravenna~~beginning of 2019 with the ramp-up finalized between April and July, at the Porto Marghera (down by 21.9%) and Dunkerque ~~(olefins), Ferrara (elastomers) and Mantova~~(down by 17.1%) sites ~~(styrene)~~ due to ~~planned shutdowns of~~unplanned shutdowns.

Plants nominal capacity is in line with the ~~plants.~~2018. The productions of Brindisi plant increased (up by 15.7%) as well as Grangemouth site (up by 20.7%), for the start-up of the new butadiene-based rubber production line. Nominal capacity of plants barely unchanged from the previous year, with an average plant utilization rate, calculated on nominal capacity ~~of 71.4% reporting a slight decrease~~was 66.8%, decreasing from ~~2015 (72.7%~~2018 (76.2%). following the aforementioned shutdowns.

~~TABLE OF CONTENTS~~

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

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(ktonnes)						(ktonnes)
Intermediates		2,972		3,334		3,417		5,818		7,130		6,595
Polymers		2,311		2,366		2,229		2,250		2,353		2,360
Total production		5,283		5,700		5,646		8,068		9,483		8,955
Consumption and losses		(2,292)		(1,908)		(2,410)		(4,307)		(5,085)		(4,566)
Purchases and change in inventories		472		9		523		524		540		257
		3,463		3,801		3,759		4,285		4,938		4,646

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

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(€ million)						(€ million)
Intermediates		2,310		1,899		1,688		1,791		2,401		1,988
Polymers		2,800		2,690		2,380		2,201		2,589		2,730
Other revenues		174		127		128		131		133		133
Total revenues		5,284		4,716		4,196		4,123		5,123		4,851

Intermediates

Intermediates revenues (€~~1,688~~1,791 million) decreased by ~~€211~~€610 million from ~~2015~~2018 (down by ~~11.1%~~25.4%) reflecting both the lower commodity prices scenario ~~that influences~~influencing average intermediates ~~prices.~~prices of main products and the lower product availability due to plant standstills. Sales ~~increased~~decreased by ~~4.6%~~18.4%, in particular for ethylene business ~~(up~~(down by ~~19.3%~~38.0%)~~. Derivatives sales registered an increased (up~~, olefins (down by ~~14.8%~~21.9%) ~~driven~~and derivatives (down by 13.4%) following the ~~combined effect of a higher demand and a higher availability of product.~~ lower product availability.

Average ~~unit~~ prices decreased by ~~11.1%~~9.9%, ~~with~~in particular olefins (down by 10.2%), aromatics ~~price lowered~~(down by ~~7% (benzene),~~5.4%) and derivatives ~~prices~~(down by ~~7.7% and olefins prices by 17.8% driven by the weakness of the market and overcapacity in Europe.~~10.6%).

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Intermediates production ~~(3,417~~(5,818 ktonnes) registered ~~an increase~~a decrease of ~~2.5%~~18.4% from ~~the last year due to increases~~2018. Decreases were registered in aromatics ~~(up~~(down by ~~2.7%~~19.6%), olefins (down by 18.9%) and in derivatives ~~(up~~(down by ~~10.2%). Olefins barely unchanged (up by 0.8%~~11.3%).

Polymers

Polymers revenues (€~~2,380~~2,201 million) decreased by ~~€310~~€ 388 million or ~~11.5%~~15.0% from ~~2015~~2018 due to ~~average unit prices~~lower volumes sold (down by ~~5.5%) and sold volumes decrease (down by 6.7%~~4.6%), ~~driven by continuing weakness of automotive sectored demand and low prices of Asian producers. These negatives were further exacerbated by~~as well as the decrease of ~~average styrenics prices (down by 6.3%) and sold volumes down by 9.1%, also due to lower production availability following~~ the ~~Mantova shutdown. Polyethylene volumes (down by 9.8%) and~~ average prices (down by ~~3.2%~~10.8%).

The styrenics business registered the decrease of volumes sold (down by 4.3%) ~~recorded a decrease.~~for lower product availability; decrease of sale prices (down by 14.7%).

~~Polymers production (2,229 ktonnes) decreased by 5.8% from 2015. Styrene productions~~Polyethylene volumes decreased (down by ~~7.2%~~5.0%) due to oversupply and mounting competitive pressure from cheaper products streams from the ~~planned Mantova standstill with~~Middle-East and the USA; decreasing of average prices (down by 7.7%).

In the elastomers business, a decrease of sold volumes (down by 4.9%) was attributable to NBR rubbers (down by 10.3%), thermoplastic rubbers (down by 14.8%) and BR (down by 3.7%); increasing of SBR rubbers (up by 1.7%) and lattices (up by 1.0%).

Polymers productions (2,250 ktonnes) decreased from the 2018 due to the lower production of ~~styrol~~elastomers (down by ~~6.4%~~7.0%), polyethylene (down by 3.9%) and ~~compact polystyrene~~styrenics (down by ~~11.2%) partly offset by higher productions of ABS/SAN (up by 9.9%~~3.8%). Polyethylene productions decreased (down by 8.6%) driven by scheduled standstills of Ragusa, Ferrara and Dunkerque partly offset by higher productions of HDPE (up by 9.4%). Elastomers productions increased (up by 7.1%), especially in BR segment (up by 15.2%), driven by higher volumes sold compared to 2015.

Capital expenditures

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

~~TABLE OF CONTENTS~~

Corporate and Other activities

These activities include the following businesses:

•

the “Other activities” segment comprises results of operations of Eni’s subsidiary Eni Rewind (former Syndial SpA) which runs ~~minor petrochemical activities and~~ reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past ~~years;~~years, as well as Eni New Energy SpA which engages in developing the business of renewable energy; 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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Seasonality

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

Research and development

~~Technology research~~Eni’s commitment and investment in Research and Development are divided into the following technology platforms, which reflect the strategic drivers of development ~~(R&D) and continuous innovation are key factors in successfully implementing Eni’s business strategies and in supporting mid and long-term performances.~~of R&D projects:

~~The Company believes that the oil&gas industry will have to face several challenges:~~

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~~uncertainty about oil&gas prices and demand;~~

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~~limited access to new low-cost hydrocarbon resources, with increasing role of unexplored oil&gas basins;~~

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~~need of a more efficient exploitation of conventional fossil sources;~~

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~~strong request of stakeholders for a~~Operational Excellence: reduction of ~~GHG emissions;~~costs and

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~~safety~~ times of operations, ~~as a crucial point~~developing key technologies for ~~business success.~~

~~In order to address the above challenges, Eni will pursue the following technological targets in the next future:~~

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reducing operational risk and maximizing operational efficiency by development of new tools for prevention and response to blow outs (mechanical barriers and equipment for the capture of subsea oil eruption)access and development of ~~tools for vessel maintenance~~assets, ensuring the highest level of sustainability, safety and ~~restoring clogged pipes;~~minimum environmental impact;

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~~strengthening technological leadership~~Carbon Neutrality: reduce, capture, transform or store CO2, develop products with “energy saving” characteristics, promote natural gas as an energy source in ~~exploration by continuously~~the transition to a low carbon energy mix, integrate renewable energies into the energy system and develop innovative energy technologies;

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

Research and development is a key element in Eni’s transformation into an integrated energy company in a low-carbon future. The availability and development of ~~proprietary tools;~~cutting-edge technological skills at the service of 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.

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~~maximizing~~Research and Development becomes, therefore, the ~~recovery factor~~lever to create value, with the aim of ~~reservoirs aiming at innovative enhanced oil recovery techniques sustainable also in low oil price scenarios;~~

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~~focusing on conversion and processing of stranded gas resources and~~minimizing the time to market that from research leads to the development of ~~proprietary~~ technologies ~~in the sector of renewable energies;~~

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~~further development of Eni’s Green Refinery processes with innovative solution for the conversion of conventional refineries into bio-refineries;~~

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~~formulations of innovative fuels, lubricants~~ and ~~bitumen that comply with European regulations and new motor specifications;~~

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~~development of new technologies for the separation, conversion, transportation and utilization of natural gas;~~

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~~commitment to transfer quickly the relevant results achieved by research and development to business units, also to the new appointed energy solution one; and~~

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~~development of innovative environmental technologies for in situ monitoring and remediation.~~

their implementation on an industrial scale.

In ~~2016,~~2019, Eni filed 5234 patent applications ~~(33~~(43 in ~~2015)~~2018).

In ~~2016,~~2019, Eni’s overall expenditure in R&D amounted to ~~€161~~€194 million which were almost entirely expensed as incurred (€~~176~~197 million in ~~2015~~2018 and ~~€174~~€185 million in ~~2014)~~2017).

Exploration & Production

~~• Oxy-Combustion.~~ Proprietary software for seismic signal processing, petroleum system modeling and flow assurance~~As part~~ that confirms and strengthens Eni’s position at the top of the ~~zero-flaring strategy, Eni is assessing through a pilot installation at~~industry, both in terms of operating results and with significant savings on the ~~New Oil Center~~cost of ~~Gela, a~~licenses and code maintenance.

Drilling automation. Two new tools addressing lost/non productive time and based on big data technology ~~for oxy-combustion, which allows to exploit low calorific tail gas by production of electricity with CO, NO~~X ~~and hydrocarbons emissions essentially absent.~~

~~• MAREnergy.~~ ~~Project aiming at the exploitation of renewable energy in the sea (from waves and wind)~~were developed since 2017 to support ~~upstream activities through the development of hybrid solutions capable of minimizing the typical variability of renewable~~operations. The first tool is e.NPT (Eni Non Productive Time) which analyzes and integrates multiple data sources in ~~energy generation.~~

~~• CO~~2 ~~-to-Oil.~~ ~~Project aiming to reduce Eni’s carbon footprint using a technology that captures CO~~2 ~~to produce a third generation bio-fuel. The emerging technology is based on the cultivation of micro-algae inside bio-reactors~~real time in order to ~~produce~~predict sticking events. The second tool is a ~~bio-algal oil suitable~~new solution enabling a near real time performance analysis to ~~feed Eni’s Green Refineries. The technology pilot plant has being built in Ragusa with start-up scheduled for March 2017.~~identify Invisible Lost Times.

~~• Chemical EOR.~~ In 2016, in Egypt three chemical EOR pilots (chemical and low salinity injection) were started in Belayim giant field. First results of the polymer injection in two producing wells confirmed the forecasted improved recovery allowing the booking of additional reserves.

• Drilling Safety ~~Technologies.~~ Technologies~~Project aiming~~: to reduce by ~~two orders~~a further order of magnitude the risk of blowout occurrence compared to the OGP reference. To achieve this goal, new technologies able to improve well integrity both during drilling and well productive life ~~have been~~are being developed. In 2016 the first test of a casing valve activated without control line and therefore suitable to be used in subsea wells, was performed; beginning of 2017 a first application in a well will be carried out.

~~Refining & Marketing~~

• Eni ~~Green Diesel+.~~Subsea Hub Technology Solutions ~~A new premium diesel containing 15% of Hydrotreated Vegetable Oil (HVO), produced in Venice bio-refinery~~: to develop, together with industry partners, technologies to significantly reduce subsea development CAPEX and OPEX by using ~~Eni/UOP’s Ecofining™ process, was launched in January with sales increase by about 20%. In November the winter diesel (Eni Green Diesel + Alpino) was also launched.~~

~~• Energy Saving Lubricants.~~ ~~In collaboration with GE a new lubricant oil for gas turbines has been developed. Its use will allow Eni to save 790 MMscf of gas~~full subsea architectures, very long step-outs and ~~44’000 tons of CO~~2 ~~emissions per year.~~

~~Renewable Energy & Environment~~

~~• Concentrated Solar Power~~. Since some years, Eni is engaged in an R&D project for the development of innovative components and engineering solutions for Concentrated Solar Power (CSP) in order to reduce capital investment and operation costs for thermal energy production via solar. In partnership with Massachusetts Institute of Technology it has been developed an innovative, low cost parabolic solar collector, easy to manufacture and assembly.life-of-field robotics. The latter feature will allow the manufacture in the same countries where they will be installed, fostering local employment and economic development. In 2016 a full-scale prototype was built in Politecnico of Milan University.program starts from lessons learned from Eni’s most recent subsea

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development projects. The objective is to increase the distance between new subsea production systems and existing floating production facilities, or connect those new subsea assets directly to shore. Cost effective and flexible extra-long subsea architectures prove to efficiently work on a wide range of applications and design basis parameters. Key enabling technologies under development are multicontrol communication, subsea power distribution, subsea boosting and thermal management.

MarEnergy (Wave Energy): Eni launched in 2016 an R&D program called MarEnergy, aiming at developing, demonstrating and deploying wave energy renewable technologies in Oil & Gas offshore operations. In the MarEnergy program Eni is both validating innovative renewable marine energy technologies, and developing Wave Energy Converters (WEC), as this type of technology resulted according to an internal assessment as the most interesting for Oil & Gas applications. Since the end of November 2018 Eni has been successfully testing the PB3 wave energy converter developed by Ocean Power Technologies (OPT) in the Adriatic Sea (Italy) nearby a producing gas platform. A second line of activity of the MarEnergy R&D program is the development of an innovative WEC in partnership with Politecnico fo Turin University and spin-off Wave for Energy. On December 6, 2018 a 50 kW subscale prototype of an Inertial Sea Wave Energy Converter (ISWEC) was installed near Ravenna (Italy). Since February 22, 2019 a pilot test with the ISWEC integrated with the Photo Voltaic system already present on the platform has been going on. On April 19, 2019 Eni, Cassa Depositi e Prestiti, Fincantieri and Terna signed a non-binding agreement to develop and build wave power stations on an industrial scale in Italy, especially near the minor islands.

Refining & Marketing and Chemicals

Methanol based alternative fuels. A new gasoline formulation containing alternative fuels (15% methanol and 5% bioethanol comprising a proper additive package to protect the engine), labeled M15, has been developed and is currently undergoing extensive road tests on five Fiat 500 cars belonging to the car sharing Enjoy fleet in Milan. M15 can provide more than 3% CO2 tailpipe emissions reduction due to the lower H/C ration and higher octane number.

i-Sigma Bio Tech lubricants. Eni R&D in collaboration with Versalis and Matrìca developed a new synthetic lubricant base stock of ester type, obtained from renewable sources. This synthetic product is featured with excellent properties in terms of oxidation stability, volatility and wear protection that are suitable for several applications in the industrial and automotive lubrication sectors. Bioester is a key component of a new SAE 10W-30 engine oil for heavy duty services (trucks, buses, and off-road vehicles) designed and tested by Eni to meet some important international technical specifications, and ready for the market under the brand name i-Sigma Bio Tech.

Energy Saving Lubricants: In collaboration with BHGE, Eni has developed an innovative low viscosity oil for turbomachinery sector, Eni OTE GT 15, that showed outstanding energy saving characteristics by reducing friction losses up to 15%, decreasing the consumption of natural gas and decreasing CO2 emissions.

Guayule. Project aiming at the production of natural latex, dry rubber and resins from Guayule (ongoing experimental cultivation in Basilicata and Sicily) with exploitation of all components with proprietary technologies and their development in the market allowing the use of whole value of the Guayule plant.

An important agreement has been signed with one of the most important international player in the field of tire manufacturing for the joint development of a common technology platform for guayule production and applications.

Bio-butadiene. A joint venture between Versalis and Genomatica has developed a process to produce 1,3 bio-butadiene from renewable sources via sugars production from biomasses, fermentation and subsequent chemical processes.

Renewable Energy & Environment

Concentrated Solar Power. The Eni R&D effort towards the definition and application of improved Concentrated Solar Power (CSP) solutions has led to proprietary technology assemblies with advantageous capital investment and operation costs. A long-term partnership with Massachusetts Institute of

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Technology and the Politecnico of Milano (that has realized the first proprietary CSP prototype) has allowed the focusing of capabilities for this purpose. The deployment phase is ongoing in the South of Italy, with a pilot plant in Gela (Sicily) and a demo plant of 1MW thermal power.

• Organic Photovoltaic. New solutions (active and buffer materials) for flexible solar cells have been developed and applied in an emerging field that relies on organic polymeric photovoltaic solutions. The developed technology solutions allow easy transportation and application wherever power is required and no grid infrastructure is available. Thanks to the light weight and the technical and operational simplicity some photovoltaic modules with inflatable support have been also developed and installed in demonstrative situations.

Energy storage. The storage of the electric energy produced from renewable sources is indeed a key issue for allowing the further development of this field. Accordingly, Eni is testing solutions for Redox Flow Batteries and for integrating these devices “conventional” electrical energy production devices such as gas turbines and diesel generators in demonstrative plants for off-grid applications. Targeting in these cases a relevant CO2 (higher that 75%) emission reduction.

Phytoremediation. Field tests showed that selected Plant Growth-Promoting Rhizobacteria able to enhance the plants biomass, increasing the uptake of metallic soil contaminants. The usage of these bacteria has been experimented in field tests for promoting the biodegradation of hydrocarbons in polluted environments (Ravenna, Priolo and Mantova).

Hydrocarbon recovery. Eni developed and applied a proprietary technology (e-hyrec®) allowing the remediation of aquifer environments through the recovery and separation of hydrocarbon contaminants. The full commercialization phase begun in the second quarter of 2018.

Soil and Groundwater Bioremediation: Eni R&D has developed through laboratory, pilot and field scale tests, technologies and site-specific protocols (e-lamina®) for treating contaminated soils and groundwater utilizing biological, environmental-friendly and cost-effective means. The protocols involve: (i) sampling and site characterization, (ii) evaluation of the bio-degradation potential by micro/meso-cosm test studies, (iii) in situ pilot plant activities, (iv) design and application of full-scale bio-remediation treatments.

Waste to Fuel. Eni ~~is evaluating~~has developed a ~~Waste-to-Fuel~~Waste- to-Fuel process able to transform wet domestic waste into bio-oils ~~suitable~~with characteristics similar to ~~feed Eni’s biorefineries~~that of a heavy oil of fossil origin, which can be used directly as a renewable component in marine fuels (bunker oil) or treated in the traditional refining processes to ~~obtain second-generation biofuels.~~produce biofuels for automotive use. The ~~pilot scale development phase~~technology consists of a heat treatment carried out directly on the wet biomass (typically containing 70 -80% by weight of water) which does not require strong dehydration pretreatment, and allows concentrating up to 75% of the ~~technology has been completed.~~

~~• Monitoring of Pollution and Remediation of Soils. Eni R&D has been active for years~~energy in the ~~development~~bio-oil from the total energy content of ~~devices and protocols able~~the feedstock. In 2018 a pilot plant treating wet domestic waste up to characterize polluted sites and monitor their remediation. Eni in collaboration with Massachusetts Institute of Technology, Consiglio Nazionale delle Ricerche, University of Piemonte Orientale, University of Rome “Tor Vergata” and Syndial, has developed and validated some original passive biomimetic samplers to determine700 kg/day was started at the available fraction of organic contaminants. The devices consist of low-density polyethylene films. In 2016 the application protocol of those devices was validated as official method of analysis by the Italian institute for the research on water (CNR-IRSA).Gela refinery.

Energy Transition

~~In 2016~~ Eni launched the “Energy Transition” R&D program with the aim of developing new technologies to promote the widespread use of natural gas, making easier its production and transport, widening its uses and ~~to decarbonize~~favoring the decarbonization of the whole value chain. In particular, the research deals with three areas of interest:

Natural gas transportation, transformation and uses,

H•2S management,

CO2 management.

On the forefront of Natural Gas ~~Transportation~~transportation and ~~Conversion.~~ ~~Transportation and use of natural gas including~~conversion, important results have been obtained for the development of ~~materials suitable to take~~a process for the ~~Adsorbed Natural Gas (ANG)~~production of methanol from natural gas. The process is based on an Eni proprietary technology ~~to an industrial scale, and the development of processes~~ for the conversion of ~~natural gas~~methane to ~~methanol. The latter seen as an important vector for~~syngas, which is cheaper and has a footprint and a weight much lower than the ~~production of low environmental impact liquid fuels and chemical products (olefins and aromatics).~~existing processes based on steam reformer.

~~• Hydrogen Sulfide.~~ ~~Development of new technologies for~~In the ~~separation and use~~area of H2S ~~both in fertilizer products~~ and ~~in materials and plastics containing sulfur.~~

CO~~• Carbon Dioxide.~~2 ~~Development of new technologies~~capture, innovative highly effective solvents for the separation of H2S and ~~use of~~ CO2 ~~comprising on-board capture of generated CO~~2 ~~in motor vehicles~~from natural gas have been identified and ~~use of CO~~2 ~~for production of plastics, fibers and building materials.~~

~~Petrochemicals~~

~~• Guayule.~~ ~~Project aiming~~tested at lab scale. Now the production of natural latex, dry rubber and resins from Guayule (ongoing experimental cultivation in Basilicata and Sicily) with exploitation of all components with proprietary technologies and their development in the market allowing the use of whole value of the Guayule plant.

~~• Bio-butadiene.~~ ~~A joint venture between Versalis and Genomatica has developed~~results is under scaling-up to a ~~process to produce 1,3 bio-butadiene from renewable sources via sugars production from biomasses, fermentation and subsequent chemical processes. The Tire Technology Committee has awarded this project~~pilot unit with the ~~“Environmental Achievement Award”.~~cooperation of an external specialized company. New ways for sulphur utilization are under consideration. Innovative sulphur-based products which can be used in agriculture have been obtained and are under testing in a field parcel in Central Italy.

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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 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.

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Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) 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. In addition, Eni uses insurance companies who it believes are established in the marketplace. 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 billion for offshore events and $1.4 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1,250 million for ~~the fleet owned by the subsidiary~~ LNG ~~Shipping in the Gas & Power segment~~tankers and time charters; $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 occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See “Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas”.

Environmental matters

Environmental regulation

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in the certain protected areas or provide special measures to be adopted to protect health and safety at workplace and health of communities that could have been affected by the Company’s activities. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. See “Item 3 – Risk factors”.

We believe that the Company will continue ~~incurring~~to incur significant amounts of expenses in order to comply with pending ~~regulations in the matter of~~ 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

~~In 2016, the main environmental efforts of the European Union continued to focus on the air quality, energy transition, circular economy and Climate Change matters.~~

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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global greenhouse gas emissions have deposited their instruments of ratification. To date, ~~the 123~~189 Parties have ratified the Convention. This important step in the common international Climate Change strategy sets out a global action plan to ~~put the world on track to avoid dangerous climate change by limiting~~keep a global ~~warming to~~temperature rise this century well below 2°~~C. By the ratification of the Convention, the governments agreed~~C above pre-industrial levels and to pursue efforts to limit the temperature increase even further to 1.5°~~C, since this would significantly reduce risks~~C.

In 2019, the UN Climate Change Conference (COP 25) had taken place in Madrid under the Presidency of the Government of Chile. The COP 25 had an important role to play in moving forward with the Paris Agreement “rule- book” implementation and it laid the basis for more ambitious emission reduction commitments from Parties at the next conference (COP 26 to be held in Glasgow, UK). Main focus areas discussed during the COP 25 were adaptation to climate impacts, ofthe support to loss and damage suffered by developing nations due to climate ~~change.~~

~~On October 4, 2016,~~change, international climate finance and others. Regarding the ~~European Parliament approved~~rules for the ~~ratification~~international carbon market (article 6 of the Paris Agreement), the COP 25 did not reach any agreement. On this topic, negotiations could not go over the impasse due to a divergence between the Parties on a few crucial points and in the end, the issue was delayed until next year’s talks.

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

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

Once implemented in legislation, the new EU 2030 GHG reduction target will entail a revision of the main targets and provisions enforced by the ~~European Union. The Paris Convention vindicates~~current EU legislation. In particular, the EU strategy in climate change defined in October 2014, when the European Council agreed on the 2030 climate and energy policy framework. In this strategy the EU stated an ambitious economy-wide domestic target of at least 40% GHG reduction for the period up to 2030 (below 1990 levels) and to a 27% share of renewable energy in final energy consumption.

~~On November 30, 2016, the following step of this strategy was written down, when the EU Commission presented the~~existing Clean Energy for All Europeans (so called ~~“Winter~~“Clean Energy Package”)~~. By this proposal,~~ developed between 2016 and early 2019, among the ~~EU is consolidating~~others commitments, set a binding target of 32% for renewable energy sources in the ~~enabling environment for the transition~~EU’s energy mix by 2030 and a binding target of at least 32.5% energy efficiency by 2030, relative to a ~~low carbon economy through a wide range of interacting policies and instruments reflected under the Energy Union Strategy, one of the 10 priorities of the Juncker Commission.~~ ‘business as usual’ scenario.

The Winter Package has three main goals: putting energy efficiency first (setting a binding 30% energy efficiency target), achieving global leadership in renewable energies and providing a fair deal for consumers. The Package includes some legislative proposals such as revision ofrevised Renewable Energy Directive ~~(“RED”) - (Directive 2009/28/CE) and revision of~~sets also the ~~Energy Efficiency Directive. For Eni’s strategies and policy on biofuels, a revision of RED has a~~target for renewable energy in the transport sector. In particular, ~~importance. In order to foster the de-carbonization and energy diversification the RED revision proposal introduces an obligation on European transport~~Member States must require fuel suppliers to ~~provide an increasing share~~supply a minimum of 14% of the energy consumed in road and rail transport by 2030 as renewable ~~and low-carbon fuels, including advanced biofuels, renewable transport fuels~~energy, of non-biological origin (e.g. hydrogen), waste-based fuels and renewable electricity. The level of this obligation is progressively increasing from 1.5 percent in 2021 (in energy terms) to 6.8 percent in 2030, includingwhich at least ~~3.6 percent of~~3.5% coming from advanced biofuels. ~~It also introduces a cap on~~In terms of environmental sustainability, high Indirect Land Use Change-risk feedstocks will be capped at 2019 levels until 2023 and then progressively phased-out up to zero by 2030.

A centerpiece of the ~~contribution of first generation biofuels (so called “food-based” biofuels) in transport sector towards~~EU’s 2030 energy and climate policy framework is the ~~EU renewable energy target, starting at 7 percent in 2021 and going down progressively to 3.8 percent in 2030 to minimize the Indirect Land-Use Change (ILUC) impacts.~~

An important part of EU Climate Strategy is covered by the Emission Trading System (ETS), which is now in the III phase (2013-2020). The Commission has already brought forward key proposals to implement the EU’sbinding target to reduce ~~greenhouse gas~~overall GHG emissions by at least 40% below 1990 levels by 2030. ~~In July 2015, it presented a proposal to reform~~To achieve this cost-effectively, the sectors covered by the EU Emission Trading System (ETS) – phase IV (2021-2030) to ensure the energy sector and energy intensive industries deliver the emissions reductions needed. In summer 2016, the Commission brought forward proposals for accelerating the low-carbon transition in other key sectors of the European economy. To achieve the at least 40% EU target, the sectors covered by the ETS(EU ETS) will have to reduce their emissions by 43% compared with 2005, while non-ETS sectors will have to ~~2005. To this end,~~reduce theirs by 30%. The ETS is about to enter in its IV phase (2021-2030), in which the ~~overall number of emission allowances~~European cap will decline at an annual rate of 2.2% ~~from 2021 onwards,~~, compared to 1.74% ~~currently.~~of the previous phase. The carbon leakage sectors will still receive 100% of the free allowances calculated with the sectorial benchmark, for all the IV phase. All the Eni’s activity sectors are included in the new carbon leakage list, excluding the extraction and production of natural gas. Currently around ~~49%~~46% of Eni’s direct GHG emissions are included within the Carbon Pricing Scheme by its participation in the EU ETS.

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

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

Air quality remains at the center of the European environmental policies and strategies. ~~On December 18, 2013,~~In 2019 the European Commission ~~adopted~~has completed a ~~package~~fitness check of ~~proposals~~the two EU Ambient Air Quality (AAQ) Directives (Directives 2008/50/EC and 2004/107/EC). These Directives set air quality standards and requirements to ~~improve~~ensure that Member States monitor and/or assess air quality in their territory, in a harmonized and comparable manner. The fitness check of the AAQ Directives was based on the analysis of the experience in all Member States, focusing on the period from 2008 to 2018 and evaluated the relevance, effectiveness, efficiency, coherence and EU added value of the AAQ Directives, in line with Better Regulation requirements.

In order to guarantee better quality standards and to shift toward a low carbon economy, in December 2017, the Commission has launched the Clean Mobility Package. This is a decisive step forward in implementing the EU’s commitments under the Paris Agreement for a binding domestic CO2 reduction of at least 40% till 2030. Its aim is to help accelerate the transition to low- and zero emissions vehicles, through a new target for the EU ~~which updated~~fleet wide average CO2 emissions of new passenger cars and vans of 30% by 2030 to provide stability and long-term direction. The Mobility Package has a 2025 intermediary target of 15% to ensure that investments kick-start already now. As the ~~air policy objectives for 2020~~confirmation of Eni’s involvement in sustainable mobility in November Eni and ~~2030. The package includes~~FCA have signed a ~~long-awaited revision of the National Emission Ceilings (NEC) Directive, a proposal~~contract to ~~address~~carry out research and develop technological applications aimed at reducing CO2 emissions ~~from medium scale combustion plants (MCP) and a proposal for ratification of the recently amended Gothenburg Protocol.~~in road transport.

On December 31, 2016, the new National Emissions Ceilings (NEC) Directive entered into ~~force. The NEC directive, based on a Commission proposal sets~~force to guarantee stricter limits on the five main pollutants in Europe: sulfur dioxide ~~(SO2)~~(SO2), nitrogen oxides (NOx), ammonia (NH3), volatile organic compounds (VOC) and primary particulate matter (PM). The Member States had time until June 30, 2018 to transpose the NEC Directive ~~must be transposed by~~and had to submit the ~~Member states by 30 June 2018. The new NEC directive repeals and replaces Directive 2001/81/EC. Each EU Member State is required to produce a~~First National Air Pollution Control ~~Program~~Programmes by ~~31 March~~April 1, 2019, setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments.

~~On December 18, 2015,~~ The NEC directive aim is to improve not only human health but also the ~~Directive No. 2015/2193/EU~~condition of ecosystems across the EU. In 2019 the Commission Guidance on the ~~limitation~~monitoring ecosystem impacts of ~~emissions of certain pollutants into~~air pollution was released. Moreover the first data on air ~~from medium combustion plants entered into force. The Medium Combustion Plant~~

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Directive (MCP Directive) regulates pollutant emissions from the combustion of fuels in plants with a rated thermal input equal to or greater than 1 megawatt (MWth) and less than 50 MWth. The MCP Directive is a part of the Clean Air Policy Package adoptedpollution impacts on December 18, 2013 and it regulates emissions of SO2, NOX and dust into the air with the aim of reducing those emissions and the risks to human health and the environment they may cause. The MCP Directive will haveecosystems was supposed to be ~~transposed~~submitted by Member States by ~~December 19, 2017. The MCP~~1 July 2019. in line with Directive ~~also ensures implementation of the obligations arising from the Gothenburg Protocol under the UNECE Convention on Long-Range Trans-boundary Air Pollution.~~2016/2284 (National Emission Ceilings).

The Industrial Emission Directive (IED) 2010/75/EU is fundamental for European industries, it provides the framework for granting permits for about 50,000 industrial installations across the EU. It lays down rules on the integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are defined by the sector specific and cross-sector Best Available Technology (BAT) Conclusions.

In 2016, the Commission has published the Implementing Decision (EU) 2016/902 of May 30, ~~May~~ 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.

~~Currently~~In February 2019, the ~~exchange~~Best Available Techniques Reference Document for the Management of ~~views between~~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 ~~Technical Working Group on~~Council, for large combustion plants (LCP – combustion installations

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

In 2017 (at the latest on May 16) all Member States must apply the rules of the new Environmental Impact Assessment Directive 2014/52/EU (EIA). The EIA Directive should simplify the rules for assessing the potential effects of projects on the environment and boarders scope of the EIA covering new issues such as climate change, biodiversity, resource efficiency and risks prevention on both human and environmental aspects.

Fluorinated gases (‘F-gases’) play an important role in the accomplishment of the Paris Agreement and in the EU environmental policy. These ozone-depleting substances are regulated by ~~F-gas~~F- gas Regulation (No. 517/2014) which applies from January 1, 2015. The new regulation strengthens the previous measures and should cut by 2030 the EU’s ~~F-gas~~F- gas emissions by ~~two-thirds~~two- thirds compared with 2014 levels. This represents a fair and cost-efficient contribution by the F-gas sector to the EU’s objective of cutting its overall GHG emissions by ~~80-95%~~80 – 95% of 1990 levels by 2050. ~~Moreover,~~In 2017, the EU continued to shape the F-gases strategy. In October 2017, the Commission Implementing Decision (EU) 2017/1984 was published in the Official Journal. The decision sets a reference values for the period January 1, 2018 to December 31, 2020 for each producer or importer which has lawfully placed on the market hydrofluorocarbons from January 1, 2015 UE of October ~~2016~~24, 2017.

During the ~~Kigali amendment~~reporting year, the EU focused on improving the environmental management principles and rule. In December, the Commission published the decision, amending the user’s guide setting out the steps needed to participate in EMAS (decision 2017/2285). The guidelines offer an additional information and guidance about the ~~Montreal Protocol (on Substances~~steps needed to participate in EMAS, which represents the voluntary participation by organizations in a Community eco-management, and audit scheme. In November, Commission Guidelines on 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 ~~Deplete~~specifies principles, requirements and guidelines for the ~~Ozone Layer) was signed in Rwanda. The Amendment adds powerful greenhouse gases hydrofluorocarbons (HFCs) to~~quantification and communication of the ~~list~~carbon footprint of ~~substances controlled under the Protocol to be phased down. HFC phasedown is expected to avoid up to 0.5 degree Celsius of global temperature rise by 2100, while continuing to protect the ozone layer.~~a product (CFP), based on International Standards on life cycle assessment.

In ~~2015~~2018 the European ~~Commission adopted~~Parliament and Council approved the directives included in the Circular Economy Package, ~~which includes revised legislative proposals~~revising the EU legislation on waste, aiming to stimulate Europe’s transition towards a circular ~~economy~~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 Member States must transpose the directives in national legislation by 5th July 2020. 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 ~~emphasizes~~also asks the ~~need~~adoption of measures to ~~move towards a lifecycle-driven ‘circular’ economy, with a cascading use~~strengthen separate collection of ~~resources and residual~~plastic waste, ~~that is close to zero. The O&G sector will have to put a significant effort to follow the “circular philosophy” by investing~~must be transposed in ~~the innovative technological solutions, optimization~~national legislations of the ~~water use, energy efficiency and~~Member States by 3rd July 2021. According to the ~~green procurement.~~

AUE Green Deal the new ~~integrated~~circular economy action plan is attended in March 2020, as part of a broader EU policy for the Arctic Region has been adopted in 2016. The policy defines the 39 actions focusing on strengthening international cooperation, tackling climate change, enhancing environmental protection and promoting sustainable development.industrial strategy.

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

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agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances ~~(chemical~~

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(chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees.

On June 1, 2007, the REACH Regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed and caused by chemicals, while enhancing the competitiveness of the EU chemical industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to the European Chemicals Agency (ECHA) how the substance can be safely used and ~~they must~~ communicate ~~the~~ risk management measures to ~~the~~ users. If the risks cannot be managed, Authorities can restrict the use of substances in different ways. Over time, ~~the~~ hazardous substances should be substituted with less dangerous ones. The deadline of the REACH registration depends on the tonnage band of a substance and the classification of a ~~substance; next and last deadline is 2018.~~substance. Eni recognizes the importance of the Regulation EC No. 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA which regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspect that concerns the exchange of information between producers and importers, as well as the users of chemical substances (“downstream users”).

The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation EC No. 1272/2008 on the classification, labeling and packaging of substances and mixtures), and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. The Regulation ~~will replace~~was replaced two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. ~~There is a transition period until 2015.~~ 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.

Following the incident at the Macondo well in the Gulf of Mexico, the U.S. Government and other governments have adopted more stringent regulations targeting safety and reliable oil&gas operations in the United States and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. Italian Authorities as well have passed legislation with Law Decree No. 128 on June 29, 2010 that introduces certain restrictions to activities for exploring and producing hydrocarbons that have been confirmed and further geographically limited by the successive Law Decree No. 134 of August 7, 2012 and by the Ministerial Decree of September 4, 2013.

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 main elements of the EU Directive are the following:

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

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

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

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

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Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents.

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Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities.

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Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore).

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Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.

We believe that Eni operations are currently in compliance with all those regulations in each European country ~~whose~~where they have been enacted.

Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will ~~likely~~probably increase in future years.

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

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

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Outsourced equipment contracted by Eni Head Quarter;

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Access Agreement to Subsea Capping Equipment consortium;

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Access Agreement to Global Dispersant Stockpile consortium;

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Eni Head Quarter proprietary equipment;

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Rapid Cube;

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Killing System.

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

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

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

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expanded public information about risks resulting from Company activities;

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

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stricter standards for inspections of Seveso establishments.

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

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HSE activity for the year ~~2016~~2019

Eni is committed to continuously improving its model for managing health, safety and environment issues across all its businesses in order to minimize risks associated with its own industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations.

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In ~~2016,~~2019, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was ~~304,~~306, of which:

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9992 certifications according to the ISO 14001 standard;

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10 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union);

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1823 certifications according to the ISO 50001 standard (certification for an energy management system);

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~~103~~83 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems -– requirements) and 19 according to the new ISO 45001 standard;

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

In ~~2016~~2019 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is ~~97%~~95% for the OHSAS 18001/ISO 45001 standard ~~OHSAS 18001~~ and ~~95%~~94% for the ISO 14001 standard.

In ~~2016,~~2019, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to ~~€1,102~~€1,323 million ~~increasing by 3.3% from 2015.~~(+5% vs 2018).

~~Environment.~~Environment. In ~~2016,~~2019, Eni incurred total expenditures of ~~€588.65~~€963 million for the protection of the environment (with ~~a reduction~~an increase of ~~5.9%~~5% with respect to ~~2015)~~2018). Environmental expenditures are mainly related to remediation and reclamation activities (€~~233.9~~367 million), waste management (€~~133.8~~248 million), water management (€62168 million), air protection (€~~47.2~~54 million) and spill prevention (€~~37.1~~41 million).

Safety. Eni is committed to safeguarding the safety of its employees, contractors and all people living in the areas where its activities are conducted and its assets located. In ~~2016,~~2018, the new legislation didn’t impact significantly procedures already in place for safety in the workplace.

The dissemination of safety culture is a ~~primary target~~value for Eni. In ~~2016,~~2019, in order to increase safety’s culture in the workforce, awareness-raising initiatives ~~continued. Road Shows~~continued:

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Safety starts @ office: realization of video clips that aim to raise awareness of virtuous and safe behaviors to be held in the office

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Inside Lesson Learned Project: dissemination and sharing of the most significant lessons learned through video in which the correct modus operandi is explained according to Eni Safety ~~Day were organized~~Golden Rules;

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Io vivo sicuro: day of sharing between employees 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

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Workshop on Product Safety: workshop on REACH and CLP Regulations with the aim of ~~sharing performance, target, new projects~~deepening the knowledge of the European Norms on chemical substances, strengthening the awareness of the responsibilities and ~~safety vision between Eni’s top management and employees and contractors.~~

~~In order to keep developing new awareness raising actions regarding safety at work, in 2016 two new initiatives were launched:~~

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~~“Inside Lesson Learned Project” to share lessons learned using video clips made by internal resources and inspired by real events occurred in~~fulfilments of the ~~company;~~organizational roles.

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“Eni in Safety 2” to increase safety culture with workshops finalized to discuss safe behaviors, responsibility and leadership in safety. The new projects will be roll out in 2017 involving employees and contractors.

In 2013, Eni launched an initiative aimed at issuing work permits in electronic form for standardizing and improving the related risk assessment process. The initiative is progressively involving all the operating sites. In 2015, Eni developed the Company Process Safety Management System for increasing the safety of its operations through still higher technical and management standards. Starting from 2016 and in following years these standards ~~will be~~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.

~~Results of efforts to achieve a better safety in all activities brought an improvement of Eni~~In 2019, the Total Recordable Injury Rate for the workforce ~~total recordable injury rate (0.35), decreased~~improved by ~~21%~~3% compared to ~~2015.~~2018 (0.34 vs 0.35).

~~As to~~

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Regarding emergency preparedness to oil spill, Eni has joined the Oil Spill Response-Joint Industry Project (OSR-JIP I & II) which was launched in December 2011 by International Association of Oil&Gas Producers (IOGP) and International Petroleum Industry Environmental Conservation Association (IPIECA) and concluded in ~~2016. The JIP executed the outstanding recommendations from the report produced by the Global Industry Response Group (GIRG)~~2016 set-up after the Macondo accident.

The ~~JIP aimed at:~~

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~~providing a forum for~~work of the five-year Joint Industry Project is now included in the Oil Spill Group that continues to develop good practice and facilitates industry forums to share ~~knowledge on the science, tools and techniques;~~

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~~representing the industry on approaches for~~ oil spill preparedness and ~~response, working closely with other associations on communications with both national~~response.

Moreover in the same framework Eni participates at two Global Initiatives jointly led by the IMO and ~~global regulatory groups;~~

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~~engaging pro-actively in broader outreach~~IPIECA: OSPRI (Black Sea, Caspian Sea and ~~communication.~~

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~~The OSR-JIP carried out specific projects dealing with exercise planning, in situ burning, dispersants advocacy-subsea, efficacy-post spill monitoring, upstream risk assessment~~Central Eurasia) and ~~response capability, etc., publishing 11 Research Reports, 9 Technical Reports~~WACAF (West, Central and ~~24 Good Practice Guidance (two are already available in Italian)~~Southern Africa).

Costs incurred in ~~2016~~2019 to support the safety levels of operations and to comply with applicable rules and regulations were ~~€287.8~~€306 million.

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

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plant and facility efficiency and reliability;

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

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

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

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

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

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training programs for medics and paramedics.

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

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

~~In 2016, Eni incurred total expenses of €47.9 million, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health, which will be~~Information about Eni’s strategy and targets in ~~line with 2016 levels in future years.~~

~~Managing GHG emissions~~

~~2016 was a relevant year for the international climate change debate, mainly due to the entry into force of the Paris Agreement on 4~~th November. The Paris Agreement and its early entry into force represents for Eni a very positive step toward a low carbon energy transition. As a major international energy company, Eni is actively involved to play a leading role to contrast climate change.

Eni recognizes indeed the scientific evidences presented in the IPCC Fifth Assessment Report and the necessity to limit the rise of the global temperature below 2 °C above pre-industrial levels. In line with this long term target, Eni has developed an integrated climate strategy with the aim of advance in the transition towards a low-carbon energy future while fulfilling the growth of energy demand. Eni’s climate strategy is composed of three main pillars: reducing and offsetting its greenhouse gas (GHG) emissions; developing a low-carbon portfolio; and committing on renewables and low carbon R&D.

~~Regarding the reduction of greenhouse gas (GHG) emissions, since 2010 years Eni reached important results, such as an absolute reduction of 31%~~scenario in ~~total direct GHG emissions, together with a 30% reduction in the carbon intensity of the Upstream business. These results were mainly driven~~accordance to standards set by ~~flaring down projects, methane monitoring campaign and energy efficiency efforts.~~

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In order to strengthen this engagement and with a forward looking perspective, in 2015 Eni launched a strategic internal Program on Climate Change aimed at developing a medium and long term roadmap able to drive Eni towards a low carbon future. In line with this Program and the abovementioned strategy, Eni published its targets and established the new “Energy Solutions” business line in order to integrate traditional energy sources with the production of energy from renewable sources.

~~In particular, by 2025 we have confirmed three main commitments focused on improving our GHG performance: to reduce by~~ ~~-43%~~ ~~vs 2014 the GHG emission intensity of our production, to reach zero routine gas flaring and to abate by 80% the fugitive emissions coming from our Upstream business.~~

In addition to these operational actions and commitments, Eni actively participates in primary international climate initiatives. In particular, in 2016 Eni contributed to further develop the “Oil and Gas Climate Initiative” (OGCI), a voluntary CEO led initiative launched in 2014 along with other companies in the oil&gas sector (currently, the ten OGCI member companies represent about 25% of global HC production). On November 4, 2016, during a high-level event in London, OGCI CEOs announced an investment of $1 billion over the next ten years to develop and accelerate the deployment of innovative low emissions technologies able to improve the management of GHG emissions and contain climate impacts of the Oil&Gas sector.

In 2016, Eni has continued its efforts in two international Public-Private Initiatives focused on operational efficiency: the “zero routine gas flaring at 2030” program of the World Bank’s “Global Gas Flaring reduction partnership” and the “Clean Air and Climate initiative - Oil & Gas Methane Partnership”, aimed at reducing methane emissions in the oil&gas value chain. About this important topic, in October 2016 was published the first report of the initiative, with details and information on Eni methane LDAR monitoring campaign during the first year of the initiative.

Thanks to its climate strategy and the ambitious targets for the future, in 2016 Eni has been recognized by the CDP as a global leader for its actions and strategies in response to climate change and was included in the prestigious A-list of CDP. Eni was the only oil & gas major achieving this high recognition.

~~Another acknowledgment of Eni’s climate leadership was the invitation to take part in the works of~~ the Task Force on ~~Climate Related~~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 ~~has the aim~~is part of ~~develop voluntary, consistent climate-related financial risk disclosures for use by companies in providing effective information to investors.~~

~~Regarding~~ Eni’s own GHG emissions management, with the aim of ensuring a comprehensive, transparent and accurate reporting for GHG emissions, in 2005 Eni introduced its own Protocol for accounting and reporting GHG emissions (GHG Accounting and Reporting Protocol), integrated in 2013 by a procedure on reporting and accounting methodologies on indirect emissions scope 3 types. This procedure was updated in 2015. According to the Eni methodology for accounting and reporting Scope 3 GHG, Eni estimates the indirect GHG emissions generated by several emission categories (e.g. purchased goods and services, use of sold hydrocarbon products, business travel, franchising, etc.) in line with the WBCSD-WRI Protocol “Corporate Value Chain (Scope 3) Accounting and Reporting Standard”.

Eni documents are an essential requirement for emissions certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to GHG, the definition of objectives and the assessment of progress. Eni GHG Protocol has been updated in 2016 to be in compliance with the National and European Guidelines (Regulation No. 601/2012) and with the best practices reference document (American Petroleum Industry Compendium). For safer and more accurate management of GHG emissions and more effective reporting, Eni provided all its business units with a dedicated database, in order to gather and report GHG emissions according to the Protocol and to ensure completeness, accuracy, transparency and consistency of GHG accounting as required by certification needs. In order to improve the Eni accounting and reporting process, Eni confirmed independent verification of its 2016 equivalent CO2 ~~emissions data (Scope 1, 2 and 3 emissions), as submitted to the CDP, and obtained the verification statement~~2019 Annual Report published in accordance with ~~ISAE 3410.~~

~~In Europe, Eni is subject to the European Union Emission Trading Scheme (EU-ETS) that was established~~Italian law and practice. These reports are not incorporated by ~~Directive No. 2003/87/EC. Effective from January 1, 2005, EU-ETS is the largest carbon market~~reference in ~~the world for exchanging emission allowances targeting industrial installations with high carbon~~this Form 20-F.

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dioxide emissions. The EU-ETS Directive states that any operator, who produces GHG emissions in excess of the amounts allowed on the basis of the national allocation plan, is required to acquire allowances on the market to cover the excess emissions or to pay a penalty.

Currently, Eni participates in the ETS with 41 plants, mostly located in Italy, which collectively represent 49% of all direct GHG emissions generated by Eni’s plants worldwide. Due to stricter allocation rules in the third phase (2013-2020) of the Emissions Trading Scheme, Eni has been receiving a lower amount of free allowances in comparison with the second phase (2008-2012). As a consequence, in the next four-year period (2017-2020), Eni will buy on the market an amount of allowances to cover GHG emissions of its industrial plants. The large majority of the deficit is concentrated in the power sector due to European allocation rules.

For additional information on Eni’s climate strategy and GHG management, please refer to the latest Eni’s Corporate Sustainability Report (“Enifor”) or to the Eni’s CDP climate change questionnaire response, both published on Eni’s website (www.eni.com).

Regulation of Eni’s businesses

Overview

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

Regulation of exploration and production activities

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

Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any ~~royalties that are payable in-kind. A license holder is generally required to pay~~ production taxes or royalties, which may be in cash or in-kind. Concession contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production activity. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. ~~In production sharing agreements, entitlements~~Contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to ~~production volumes are defined on the basis of contractual agreements drawn up with state oil companies~~hydrocarbon reserves. The company holding the ~~concessions. Such contractual agreements regulate the recovery of costs incurred for the~~mining concession has an exclusive right on exploration, development and ~~operating~~production activities, ~~(Cost Oil)~~sustaining all the operational risks and ~~give entitlement~~costs related to the exploration and development activities, and it is entitled to the productions realized. As a compensation for mineral concessions, pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with 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 ~~exceeding volumes destined~~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 ~~costs~~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 ~~and “buy-back”~~ contracts.

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

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Regulation of the Italian hydrocarbons industry

Exploration & Production

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

Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are the property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession, in each case granted by the Minister of Economic Development. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State (only for initial acreages larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the field depletes.

These provisions are to be coordinated with a new law effective as of February 12, 2019 (Law 12/2019 – ex “D.L. Semplificazioni”), which requires certain Italian administrative bodies to define within eighteen months a plan (PiTESAI) aiming to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, (within two years) it is established a moratorium on exploration activities, including the award of new exploration leases. 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, the general moratorium on exploration activities is revoked and application for new concession permits can be filed. According to the statute, areas that suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline.

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

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

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

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the Law 8/2020 – “D.L. Milleproroghe” which extends the time required for definition of PiTESAI by further 6 months (until February 2021) and the moratorium for prospecting and research by 6 months (until August 2021).

Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 – Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with ~~fixed amount of exemption. Only~~exemptions only for on shore gas concessions with production lower than 10 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to ~~20% for oil&gas,~~20,06%, with no exemptions).

Gas & Power

~~Natural~~Wholesale gas market in Italy

~~Legislative Decree No. 130 of August 13, 2010 containing measures for increasing competition~~In the last decade, and even more in the ~~natural~~last years, a number of new rules have been introduced in order to improve liquidity and efficient functioning of the Italian wholesale gas market, fostering competition and ~~transferring the ensuing benefits to final customers and Law Decree of December 23, 2013 containing measures to promote gas market liquidity~~

In 2011, Legislative Decree No. 130 of August 13, 2010 titled “New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers” became effective. This new regulation replaced the previous system of gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 by introducing a 40% ceiling to the wholesale market share of each Italian gas operator who inputs gas into the Italian backbone network. In the frame of Legislative Decree No. 130/2010 Eni built new storage capacity for about 2.64 BCM; as a consequence the above mentioned cap to its market share in Italy rises from 40% to 55%. In the case of violations of the mandatory threshold, Eni is obliged to execute gas release measures at ~~regulated prices up to 4 BCM over a two-year period following the ascertainment of the breach. Access to the new storage capacity was reserved to industrial customers.~~

The Law Decree of December 23, 2013, converted into Law on February 21, 2014, establishes that any operator with a wholesale market share higher than 10% is obliged to offer on the natural gas forward market a volume of natural gas corresponding to 5% of the annual imported volumes. The obligation to offer should be combined with a corresponding obligation to bid on the same ~~market;~~time improving the ~~spread between bid and ask prices has to~~system security of supply. Among such new rules, it could be ~~lower than an amount defined by the Minister of Economic Development, based on a proposal by the AEEGSI. AEEGSI also defines the modalities for the fulfillment of the above mentioned obligation.~~

worth mentioning:

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Eni’s management is monitoring these issues with a view of assessing any possible financial or economic impact associated with the enacted measures and their evolution. Management also believes that these regulations will increase competition in the wholesale natural gas market in Italy leading to further margin pressures.

~~Law Decree No. 1 of January 24, 2012 for new liberalization measures in Italy~~

~~Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so-called Liberalization Decree was converted to Law No. 20 on March 24, 2012. This law aimed to:~~

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enhance competitiveness in gas tariffs to residential customers and in the distribution of refined products. The AEEGSI, in charge with setting pricing mechanisms for supplies to final users, starting from the second quarter of 2012 updated the indexation mechanism by gradually increasing the weight of spot prices in the indexation of the supply costs of gas that previously used to be oil-linked; and

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~~reform the storage system introducing market-based~~Market based mechanisms for the allocation of storage ~~capacity,~~capacities and of regasification capacities: moving away from the traditional ~~“pro-rata”/tariff system,~~allocation criteria based on tariffs, new auction mechanisms were implemented that enabled market players to express the market-value of storage and ~~with~~of regasification capacities, while at the ~~aim~~same time ensuring the allowed revenues of storage operators and LNG terminal operators by means of specific parallel measures. Thanks to ~~reduce~~these reforms, much higher levels of capacity bookings have become structural for both types of infrastructures, and more LNG deliveries have been attracted recently to the ~~cost~~country, to the benefit of ~~natural gas for industrial customers. In particular:~~security of supply and of market competition.

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for an amount determined by the Ministry itself, storage capacity is primarily reserved for the offer to industrial sector of an integrated service (international transport of liquefied natural gas, regasification and storage) allowing them to supply natural gas directly from abroad in the form of liquefied natural gas; and

~~the remaining amount of storage capacity is assigned via auction procedures devoted to the modulation needs.~~

Based on the principles described above, the Minister of Economic Development and the AEEGSI establish every year the detailed criteria for the allocation of gas storage capacities. In 2016, 1BCM of bundled storage and regasification capacity was offered to the industrial sector.

~~Negotiation~~An organized market platform (MGAS) for gas trading and gas balancing market,

~~In compliance with~~ managed by the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry of Economic Development published a decree that implements a trading platform for natural gas from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform (MGAS) are entrusted to an independent operator ~~the~~ Gestore dei Mercati Energetici (GME)~~, an Italian agency. In the MGAS, parties authorised to~~ which also acts as a central counterparty, where different market participants (including TSO) can carry out spot and forward transactions at the “Punto di Scambio Virtuale” (PSV -

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Virtual Trading Point) ~~may make forward~~. In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS: such activity is based on the service provided by some liquidity providers, in order to boost liquidity and ~~spot purchases and sales of volumes of natural gas. In~~trading activity on the ~~MGAS, GME plays~~same exchange, initially for the ~~role of central counterparty~~day-ahead market but with possible future extension to the ~~transactions concluded by Market Participants.~~within-day section and to the forward section of the MGAS.

~~In October 2016 the~~

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A new gas balancing regime, -entered into force in October 2016 as an evolution of the one already in place ~~- has entered into force in the Italian system~~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 ~~Snam Rete Gas~~the TSO about the daily gas consumption. The new gas balancing regime provides ~~for:~~

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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 ~~the~~their gas ~~nominations;~~

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~~the possibility for shippers~~flow nominations and to trade on the market with other shippers and/or with the TSO itself (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities).

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~~the incentive for shippers to balance their position via penalizing imbalance prices.~~

~~To foster market liquidity, starting from April 2017 all of the above-mentioned gas trading activities will be concentrated on the MGAS, managed by GME, as one single platform.~~

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

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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 ~~AEEGSI holds~~ARERA retains a power of surveillance on this matter ~~(see below) under~~as per Law No. 481/1995 (establishing the ~~AEEGSI)~~ARERA) and Legislative Decree No. 164/2000. Furthermore, the ~~AEEGSI~~ARERA is still

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entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by ~~AEEGSI~~ARERA beside their own price proposals.

In 2013, a new tariff regime was fully enacted ~~for~~by ARERA targeting Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the ~~AEEGSI~~ARERA are residential ~~clients (including residential buildings consuming less than 200,000 CM/y).~~clients. With Resolution No. 196 effective from October 1, 2013, the ~~AEEGSI~~ARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices ~~versus~~at the ~~previous~~TTF (Title Transfer Facility) hub in Northern Europe, replacing the then current regime that provided a mix between an oil-based indexation and spot prices.

The new tariff regime intended to partially offset the negative impact born by wholesalers due to possible indexation mismatches by introducing a pricing component intended to ~~cover the risks and costs of the supplies to wholesalers.~~compensate wholesalers for losses that they would incur on those risks. Furthermore, it was provided a stability mechanism whereby a wholesaler part of a long-term, take-or-pay gas supply contract ~~may~~could opt ~~for being~~to be reimbursed offor the possible negative difference between the oil-linked costs of gas supplies and spot prices in the two thermal years following the implementation of the new ~~regime implementation;~~regime; conversely, in case spot prices would fall below the oil-linked cost of gas supplies in the following two thermal years, the same wholesaler had to refund customers of the difference. ~~Based on this compensation mechanism, which run out after September 2016, Eni totalled about €160 million of reimbursement over three thermal years, starting~~Those provisions explicated their effects in ~~October 2013 and ending in September~~2014 – 2016.

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

~~Furthermore,~~This new gas tariff indexation aiming at safeguarding the ~~new tariff mechanism indexed~~households was initially intended to ~~TTF (Title Transfer Facility) for residential clients will be applicable until the end of thermal~~remain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year ~~2017 - 2018. However, a~~(as per Law Decree ~~still under discussion at the Italian Parliament, is expected~~91/2018), and finally has been prorogated to ~~increase competitive pressure with the abrogation of the~~January 1st 2022. From that point onwards, households in Italy will no longer have access to regulated tariffs for gas supplies. Consumers will have to choose among the different pricing proposals made by gas selling companies. The ARERA has established that gas selling companies comply with certain requirements about the offerings to customers which include at least two pricing indexations (fixed and ~~power effective from July 1, 2018. Referring to~~variable), both complemented with contractual conditions regulated by the ARERA. Management believes that this development will increase competition in the Italian retail market for selling gas.

In the electricity market ~~residential customers would choose tariffs on the free market, potentially, lower than~~ the regulated ~~ones. For the gas market, similar competitive impact cannot~~prices phase out will be ~~excluded following the adoption of the same price regulation regime.~~effective: from January 1st 2021 for small enterprises (enterprise which employs fewer than 50 persons and whose annual turnover and/or annual balance sheet total does not exceed 10M€) and from January 1st 2022 for households and microenterprises (enterprise which employs fewer than 10 persons and whose annual turnover and/or annual balance sheet total does not exceed 2M€).

Similarly other Regulatory Authorities in European countries where Eni is present have issued regulations referring to hub component in the pricing formulas related to retail clients, as well as measures to boost liquidity and competitivenessOther regulatory developments in the gas and electric sector in Italy and Europe

Within the scope of access criteria to the main gas logistic infrastructures, and of the related access costs, the risk factors for the business are linked to the periodic processes by which each European country reviews the definition of economic conditions and access rules for transportation, LNG regasification and storage services. Concerning gas transportation tariffs, in Italy and in some of the main European countries the revision processes aimed at defining the tariff criteria applicable for the next regulatory period (2020-2023) were recently concluded, with overall positive effects; possible new changes may concern the regasification sector, featuring either risks or opportunities for the business.

Besides, in the coming years the gas sector regulation could be concerned by modifications, potentially relevant, linked to the adjustments that will be necessary because of the evolution of European policies and regulations in the energy transition context, coherently with the decarbonization targets in the energy sector and, therefore, with the related development of renewable and decarbonized gases and new technologies enabling higher integration between the gas and the power sectors.

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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.

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 ~~introduced with Law No. 9/1991 and No. 239/2004 (Article 1, paragraphs 56, 57 and 58) significantly changed the norms introduced in the 1930’s that required that any~~on refining activity ~~be handled under a concession from the state. Today an authorization is required~~in Italy provides that Italian administrative bodies authorize plans filed by refining operators intended to set up new processing and storage plants and ~~for any change in the~~to upgrade capacity, ~~of mineral processing plants,~~ while all other changes that do not affect capacity can be freely implemented. ~~Another simplification measure~~This regime was ~~introduced~~streamlined by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as “strategic ~~settlements”~~installations” that need authorization from the State, in agreement with the ~~relevant Region, and imposes~~local administrations. The Decree introduced a ~~single~~unitized process of authorization that must be ~~closed~~finalized within 180 ~~days. Management expects no~~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 ~~and Taranto refineries as planned in the medium term.~~underway.

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Marketing. Following the enactment of the ~~above mentioned~~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 ~~freely~~ 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. ~~Eni expects developments on this issue to further increase pressure on selling margins~~Furthermore, the law 205/2017 provides some measures for preventing of tax evasion in the ~~retail marketing~~sale of ~~fuels and~~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 ~~reduce opportunities of increasing Eni’s market share in Italy.~~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. 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) ~~upon the closure of at least 7,000 service stations,~~ 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~~-party access to unused storage capacity for petroleum products. ~~With~~Subsequently, various regulations have been enacted in Italy with the ~~same goal~~aim of ~~renewing the Italian distribution~~improving network ~~Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network,~~efficiency, modernizing service stations and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up ~~of new stations and~~ the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities. After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012market. Currently, all service stations ~~must be~~are provided with self-service equipment and ~~that Regions will update their regulations in order to allow~~ the sale of non-oil products ~~in all service stations.~~ has been broadly introduced by local administrative bodies.

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Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations, which might ~~prejudice~~limit the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours.

The new regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/UE on alternative fuel infrastructures – has introduced minimum requirements for the construction of infrastructure for the development of alternative fuels to mitigate the environmental impacts of the transport sector. The legislation established, furthermore, an adequate number of charging stations accessible to the public to be created throughout the country by 2020.

Finally, Law no. 124/2017 aims to promote the structural reorganization of the fuel distribution network also in order to increase competition and efficiency. The law requires the closure of fuel stations that are incompatible with road safety regulations and environmental streamlining procedures for the decommissioning.

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

In order to support ~~efficient operators.~~the achievement of the renewables target in the transport sector established by the EU and national laws, the Ministerial Decree of March 2, 2018, provides the legislative framework to incentivize the production of both biomethane and other advanced biofuels to be used in the transport sector.

The Decree provides incentives for plants starting operations between 2018 and 2022 and to plants that are converted to biomethane production.

The incentive consists in an allocation of a Certificate (CIC) for every 10 Gcal of biomethane produced. The certificate has a market value since fossil fuel marketers have to sell a minimum percentage of biofuels annually, for which they receive the same Certificates.

In order to access to incentives, producers must comply with legal and technical regulations governing the quality and certification of the produced biomethane, verified by the competent Authority (Gestore dei Servizi Energetici, GSE).

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

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 several Acts (Law no 157/2019 and Law no 141/2019) and 2020 budget law, new measures for sustainable mobility have been adopted in order to decarbonize the transport sector, through incentive mechanisms for low-emission vehicles.

Petroleum product ~~prices~~prices.. Petroleum ~~product~~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 ~~Productive Activities;~~Economic Development; such recommendations are considered by service station operators in establishing retail prices for petroleum products.

Compulsory ~~stocks~~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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company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain

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minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain.

As of December 31, ~~2016,~~2019, Eni owned ~~5.2~~5,6 mmtonnes of oil products inventories, of which ~~3.6~~3,2 mmtonnes as “compulsory stocks”, ~~1.4~~2,2 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.2 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil ~~(37%~~(34%), light and medium distillates (37%), refinery feedstock ~~(19%~~(20%), fuel oil ~~(5%~~(4%) and other products ~~(2%~~(5%) were located throughout the Italian territory both in refineries ~~(80%~~(85%) and in storage sites ~~(20%~~(15%).

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts ~~does~~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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In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among

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competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers.

Property, plant and equipment

Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. The Company enters into operating lease contracts with third parties to hire plant and equipment such as floating production and storage offloading vessels (FPSO), drilling rigs, time charter, service stations and other equipment. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’ worldwide proved oil&gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas.

Organizational structure

Eni SpA is the parent company of the Eni Group. As of December 31, ~~2016,~~2019, there were ~~218~~225 subsidiaries and ~~103~~110 associates, joint ventures and joint operations that were accounted for under the equity or cost method or in accordance to Eni’s share of revenues, costs and assets of the joint operations calculated based on Eni’s working interest. Information on Eni’s investments as of December 31, ~~2016~~2019 is provided in ~~Note 48~~the notes to the Consolidated Financial Statements.

Item 4A. UNRESOLVED STAFF COMMENTS

None.

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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

Key consolidated financial data

2014 2015 2016
(€ million)
Net sales from operations from continuing operations 98,218 72,286 55,762
Operating profit (loss) from continuing operations 8,965 (3,076) 2,157
Net profit (loss) attributable to Eni from continuing operations 1,720 (7,952) (1,051)
Net profit (loss) attributable to Eni from discontinued operations (417) (826) (413)
Net profit (loss) attributable to Eni 1,303 (8,778) (1,464)
Net cash provided by operating activities - continuing operations 14,469 12,875 7,673
Capital expenditures - continuing operations 11,178 10,741 9,180
Investments and purchases of consolidated subsidiaries and businesses 408 228 1,164
Shareholders’ equity including non-controlling interest at year end 65,641 57,409 53,086
Net borrowings at year end 13,685 16,871 14,776
Net profit (loss) attributable to Eni basic and diluted from continuing operations (€ per share) 0.48 (2.21) (0.29)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations (0.12) (0.23) (0.12)
Net profit (loss) attributable to Eni basic and diluted 0.36 (2.44) (0.41)
Dividend per share (€ per share) 1.12 0.80 0.80
Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage)(1) 0.21 0.29 0.28

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

(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 ~~2016,~~2019, net profit attributable to Eni’s shareholders was €148 million, much 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.

The 2019 results were negatively affected by a challenging operating and trading environment, reflecting a slowdown in the global macroeconomic cycle, a deceleration in international trade triggered by the “trade dispute” between the US 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 demand for energy commodities and global consumption of fuels and plastics, increasing the negative impact of 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 ~~net loss pertaining to continuing operations~~decline in oil and gas realized prices, as well as in products margins in all of ~~€1,051 million, with a significant improvement compared to last year’s loss of €7,952 million. The~~its business segments. Prices and margins reductions negatively affected the reported operating profit ~~was €2,157 million compared to~~for an ~~operating loss of €3,076 million a year ago.~~estimated €2.5 billion. The ~~recovery~~main negative factor were lower gas prices in ~~oil markets, that has begun in~~all geographies with the ~~second half of 2016 favorably affected~~worst declines recorded by the ~~full-year results of operations and the assets carrying amounts.~~

~~Better market fundamentals were factored in an upward revision to management’s long-term~~European benchmark gas spot price ~~assumption for the benchmark Brent to 70$ per barrel (in 2020 real terms)~~“PSV”, which was ~~adopted in~~down by 34% and negatively affected the ~~financial projections~~revenues of the ~~2017-2020 industrial plan and in assessing~~E&P segment relating sales volumes of equity gas. Furthermore, the ~~recoverability~~result of the ~~Group assets carrying amounts as~~E&P segment was significantly and negatively affected by lower re-selling prices of ~~December 31, 2016. In 2015, management assumed~~volumes of gas entitlements of a long-term Brent price of 65$ per barrel. This upward revision triggered the reversal of prior impairment losses for €1,005 million post-tax at oil&gas properties, which helped mitigate impairment lossesLibyan partner due to a ~~lowered outlook for gas~~different indexation between the procurement costs, which were oil-linked, and the reselling price which was benchmarked to spot prices in ~~Europe and other drivers, as well as other non-recurring charges for an overall negative impact of €831 million.~~

OnEurope. Due to different trends in the ~~contrary,~~indexation, this resale activity resulted in a loss to Eni, which also negatively impacted the ~~FY 2015 result was negatively affected by the recognition of material, post-tax charges of €8.5 billion. Those comprised impairment losses of upstream assets (€3.9 billion) and the~~Group tax rate.

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Prices realized at sales volumes of equity liquids were driven down by a reduction in prices of the main crude oil benchmarks, with the Brent price down by 9% for the year. Margins on sales of refined products, petrochemicals products and LNG also declined remarkably.

The Group performance was also negatively affected by a number of incidents at production plants, such as the fire that occurred at the Priolo chemical cracker in January, and unplanned standstills or outages, like in the case of the Goliat oilfield in Norway, the Bayernoil refinery, the Porto Marghera and the Dunkerque crackers. These negative effects were partly offset by higher hydrocarbon production, a favorable product mix due to higher incidence of barrels with higher-than-average profitability, efficiency and optimization measures and steady results reported by the retail businesses, which include the gas & power retail segment as well as the marketing of fuels at both retail and wholesale markets, leveraging on effective marketing actions and continuing product/service innovation. Management estimated that this positive factors improved the operating profit by 5%. Furthermore, the operating profit was negatively affected by the incurrence of approximately €2.2 billion of impairment losses, which were mainly recorded at oil and gas properties and refineries driven by a revised refining margin scenario and downward reserve revisions and lower expected production rates.

Net profit for the year was also negatively affected by lower net income from investments (down by €902 million), due to the fact that the 2018 financial statements accounted for the gains on the Vår Energi business combination (€889 million) and a reversal of a prior-year impairment loss of €262 million made at the Angola LNG equity-accounted entity. Finally, net profit was negatively affected by an increased tax rate, which was due to a higher share of taxable income reported by the Exploration & Production segment in countries subject to higher-than-average tax rates, a loss incurred in reselling volumes of gas entitlements of a Libyan partner, while taxable losses were recorded in jurisdictions with a lower-than-average statutory tax rate. The Group tax rate was also impacted by the write-off of deferred tax assets ~~for €1.8~~of approximately €0.9 billion due to ~~a lowered profitability outlook. Furthermore,~~projections of lower future taxable profit at Italian subsidiaries.

Hydrocarbons production came at 1.74 mmBOE/d and was flat y-o-y. Considering constant prices at PSAs’entitlements and net of portfolio divestments and one-offs, production would have grown by 4% driven by Eni’s successful strategy of reducing the ~~2015 charges included the impairment~~time-to-market of the Chemical business (€1 billion), the carrying amount of which was aligned to the expected fair value based on a negotiation then ongoing to establish a joint venture with an industrial partner. Subsequently, Eni and the potential buyer failed to close the negotiation. Finally, other extraordinary charges of €1.8 billion were incurred mainlyits reserves as witnessed by new field start-ups in the ~~G&P segment (for more information about extraordinary charges of G&P segment, see~~year and fast ramp-up at core projects like the ~~paragraph “Operating profit by segment”)~~Zohr gas field in Egypt. The reserve replacement ratio was 117% on all-sources basis; when stripping out asset purchases and divestments the ratio was 92%.

Nevertheless, the 2016 underlying performance was negatively affected by a continued slump in commodity prices especially in the first half of the year which determined y-o-y declines in average crude oil prices (down by 16.7%, from 52.5 $/b reported in 2015, to 43.7 $/b in 2016), gas prices (down by 28.2%) and refining margins (down by 49.4%). These declines drove a 23% reduction in the Group consolidated turnover. Other factors negatively affecting the performance were a four and half-month shutdown of the Val d’Agri oil complex in Italy and lower one-off gains in the Gas&Power segment in connection with an ongoing renegotiation process of its long-term gas supply contracts. Management implemented a number of initiatives to withstand the negative trading environment, including tight investment selection, with capex down by 15% (19% y-o-y at constant exchange rates), control of E&P operating expenses (down by 17%), optimizations of plant setup at refineries and chemical plants, savings on energy consumptions and logistic costs and G&A cuts. All these measures improvedAdjusted results

Adjusted operating profit and adjusted net profit are determined by around €1.7 billion. Finally, income taxes declined by €1,186 million due to the above mentioned extraordinary drivers. The tax rate was affected by the high relative incidence on taxable profit of results earned at PSA contracts, which are characterized by higher-than-average rates of taxes.

Overall management estimated that the increase in the Group operating results of approximately €5.2 billion (from an operating loss of €3.08 billion in 2015 to a profit of €2.16 billion in 2016) was due to the following factors:

•

~~a positive €1.7 billion gain associated with efficiency initiatives, cost reductions, lower depreciation and amortization, as well as a decreased exploration expenditure;~~

•

~~a positive €8.6 billion effect due to lower asset impairments and lower other extraordinary charges as well as a lower inventory holding valuation allowance;~~

~~These positives were partly offset by:~~

•

~~a negative €3.3 billion impact due to lower commodity prices and margins;~~

•

a negative €0.6 billion effect due to the four and a half months shutdown of operations at the Val d’Agri profit centre (see Item 4 – Exploration & Production – Eni’s principal oil&gas properties) and in the Gas & Power segment lower one-off gains related to the renegotiations of gas contracts;

•

~~a negative €1.2 billion associated with the accounting of Saipem as discontinued operation in 2015. Due to this accounting method, the 2015 result of the continuing operations benefitted~~excluding from the elimination upon consolidation of then intercompany purchases of capital goods and other services, mainly oilfield services to the E&P segment. This reflected the fact that in 2015 for accounting purposes Saipem was a fully consolidated subsidiary as Eni still exercised control at the balance sheet date. In 2016 due to the loss of control, Saipem was derecognized from the beginning of the year. Therefore, in 2016 the purchases of capital goods and services from Saipem were accounted as expenses from third parties incurred by the continuing operations.

In FY 2016, the Group net loss pertaining to Eni’s shareholders amounted to €1,464 million. This included a loss in the discontinued operations of €413 million relating to an impairment charge taken to align the book value of Eni’s retained interest in Saipem to its fair value, equal to the market capitalization at the date of loss of control (January 22, 2016) with a charge of €441 million.

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~~The table below sets forth for the~~ reported ~~periods details of certain, identified gains and charges included in net loss. These gains and charges mainly related to~~results inventory holding gains or losses and non-core gains and losses ~~asset impairments, reversals~~(pre and post-tax, respectively) that in our view do not reflect the ordinary results of ~~prior impairment losses, estimate revisions, risk and other provisions, write downs of deferred tax assets, capital gains on investments and other tangible assets.~~

Year ended December 31,
Eni Group 2014 2015 2016
(€ million)
(Profit) loss on inventory 1,460 1,136 (175)
Environmental provisions 179 225 193
Impairment losses (impairment reversals), net 1,272 6,534 (459)
Impairment of exploration projects 169 7
Net gains on disposal of assets (24) (407) (10)
Risk provisions (35) 211 151
Provision for redundancy incentives 4 30 47
Fair value gains/losses on commodity derivatives (16) 164 (427)
Reclassification of currency derivatives and translation effects to management measure of business performance 229 (63) (19)
Estimate revision of revenues accrued in the gas retail business 484 161
Valuation allowance of disputed receivables 410
Write-off of the damaged units of the EST conversion plant at the Sannazzaro refinery 193
Provision for removal and clean-up of EST conversion plant 24
Compensation gain on part of a third-party insurer relating to the EST plant incident (217)
Other 303 301 279

Total net charges (gains) in operating profit 3,372 8,784 158
Capital gains on disposal of investments (159) (33) (57)
Write downs of investments and financing receivables (38) 506 483
Write down of deferred tax assets/utilization of deferred tax liabilities 1,045 1,740 170
Gain on a tax dispute relating to the Libyan Tax (824)
Tax effects on the above listed items and other items (13) (1,321) (98)
Tax effects on (profit) loss on inventory (452) (354) 55

Net (charges) gains in net profit 2,931 9,322 711
Net (charges) gains attributable to non-controlling interest 452 53
Net (charges) gains attributable to Eni 2,479 9,269 711

In evaluating the Company’s underlying performance and with the objective of better explaining year-on-year changes, management has considered to separate from the other drivers of the Group performance the impact of the following items:

•

the above listed gains and charges amounting to a post-tax loss of €9,269 million and €711 million in 2015 and in 2016, respectively, which include an inventory holding post-tax loss of €782 million in 2015 and a post-tax profit of €120 million in 2016; and

•

~~profit on intercompany transactions with the discontinued operations for €514 million in 2015, which are eliminated upon consolidation.~~

On that basis, management has calculated a Non-GAAP measure of operating profit that would amount to €2,315 million for 2016, down by €2,171 million from 2015. A low commodity price environment accounted for a decline of €3.3 billion, while a four-month and half shutdown of operations at Val d’Agri and lower non-recurring gains in G&P accounted for €0.6 billion. Efficiency gains and a

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reduced cost base, mainly in the E&P segment, helped mitigate the negative factors and improved the performance by €1.7 billion. The corresponding Non-GAAP measure of net loss would amount to €340 million, down by €1,143 million from 2015 due to a lower operating performance, declining results from equity-accounted entities reflecting weak commodity prices and a higher Group tax rate mainly driven by the E&P segment.our operations.

Adjusted operating profit (or loss) and adjusted net profit (or loss) provide management with an understanding of the results from our ~~base~~underlying operations ~~by excluding the effects of certain disposals~~ and ~~special charges or gains that do not reflect the ordinary results of our operations. Adjusted measures of profitability~~ are used to evaluate our period-over-period operating performance, as management believes these provide a more comparable ~~measure~~measures as they adjust for disposals and special charges or gains not reflective of the ~~normal trend results of~~underlying trends in our business. These Non-GAAP performance measures may also be useful to an investor in evaluating the underlying operating performance of our business and in comparing it with the performance of other oil&gas players, because the items excluded from the calculation of such measures can vary substantially from company to company depending upon accounting methods, management’s ~~judgement,~~judgment, book value of assets, capital structure and the method by which assets were acquired, among other factors.

In 2019, 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 million in net profit and of €2,165 million in operating profit, including an inventory pre-tax gain of €223 million (€157 million post-tax).

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

	Year ended December 31,
Eni Group	2019		2018		2017
	(€ million)
(Profit) loss on inventory		(223)		96		(219)
Environmental provisions		338		325		208
Impairment losses (impairments reversals), net		2,188		866		(221)
Net gains on disposal of assets		(151)		(452)		(3,283)
Risk provisions		3		380		448
Provision for redundancy incentives		45		155		49
Reinstatement of Eni Norge amortization charges(1)				(375)
Fair value gains/losses on commodity derivatives		(439)		(133)		146
Reclassification of currency derivatives and exchange effects to management measure of business performance		108		107		(248)
Estimate revision of revenues accrued in the gas retail business						64
Valuation allowance of doubtful accounts(2)		123				616
Compensation gain on part of a third-party insurer relating to the EST plant incident		(88)
Other		261		288		231
Total net non-core items in operating profit		2,165		1,257		(2,209)
Finance expenses		(42)		(85)		502
of which: reclassification of currency derivatives and exchange effects to management measure of business performance		(108)		(107)		248
Capital gains on disposal of investments		(46)		(909)		(163)
Write downs of investments and financing receivables		166		67		537
Write down of deferred tax assets/utilization of deferred tax liabilities		893		99
Tax effects relating to the US tax reform						115
Tax effects on the above listed items and other items		(474)		55		160
Tax effects on (profit) loss on inventory		66		(27)		63
Net non-core items in net profit		2,728		457		(995)
Net (charges) gains attributable to non-controlling interest
Net non-core items attributable to Eni		2,728		457		(995)

(1)

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

(2)

In 2019, this item relates to credit losses recognized in connection with the renegotiation of a petroleum contract. In 2017, this item mainly related the retail G&P business for the estimate made in accordance with the expected loss accounting model net of the estimate made in accordance to the incurred loss accounting for credit losses.

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The Group underlying performance – i.e. excluding non-core gains and losses and the inventory holding profit – was an adjusted operating profit of €8,597 million compared to €11,240 million in 2018, down by 24% or by €2.64 billion. The decrease in adjusted operating profit was driven by lower results in the E&P segment (down by €2.21 billion) and in the Refining & Marketing and Chemical segment (down by €0.43 billion), partly offset by the increase in the Gas & Power segment (up by €0.11 billion). The main reasons for the decline were the following:

•

Unfavorable trends in prices and margins of the products that we produce and sold, which negatively impacted the performance for about €2.5 billion. This impact also included a loss incurred at the reselling of volumes of gas entitlements of a Libyan partner due to a mismatch between the indexation of the procurement costs vs. the reselling price as discussed above;

•

The business combination that involved our former subsidiary Eni Norge which was consummated at the end of 2018 and impacted the comparability of results due to loss of control and de-recognition at that date;

•

A flattening yield-curve which increased the present value of the capitalized asset retirement costs in the E&P, thus resulting in higher DD&A charges through profit estimated at €200 million.

These negative trends were partly offset by a number of positive drivers, which comprised increased production volumes of hydrocarbons coupled with a better production mix, better results earned at our retail businesses and margin improvements achieved in the wholesale gas&power business which leveraged its portfolio of assets, long-term gas contracts, power plants and logistic capabilities to benefit from market volatility. Management estimated that the Group internal performance increased operating profit by 5%, 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.

Excluding non-core items and the inventory evaluation profit, adjusted net profit for 2019 was €2.876 million, 37% lower than in 2018 when adjusted net profit came at €4.583 million. The result was negatively affected, in addition to a lower operating performance, by an increased Group tax rate which was due to a higher share of taxable income reported by the Exploration & Production segment in countries subject to higher-than-average tax rates, a loss incurred in reselling the gas entitlements of a Libyan partner, while taxable losses were incurred in jurisdictions with a lower-than-average statutory tax rate.

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,
2014 2015 2016
(€ million)
GAAP measure of operating profit of continuing operations 8,965 (3,076) 2,157
Identified net charges and inventory holding gains and losses 3,372 8,784 158
Elimination upon consolidation of intercompany transactions with discontinued operations (1,114) (1,222)
Non-GAAP measure of operating profit of continuing operations 11,223 4,486 2,315
GAAP measure of net profit of continuing operations 1,720 (7,952) (1,051)
Identified net charges and inventory holding gains and losses 2,479 9,269 711
Elimination upon consolidation of intercompany transactions with discontinued operations (476) (514)
Non-GAAP measure of net profit of continuing operations 3,723 803 (340)
GAAP measure of net cash provided by operating activities from continuing operations 14,469 12,875 7,673
Elimination upon consolidation of intercompany transactions with discontinued operations (925) (720)
Non-GAAP measure of net cash provided by operating activities from continuing operations 13,544 12,155 7,673

	Year ended December 31,
	2019		2018		2017
	(€ million)
GAAP measure of operating profit		6,432		9,983		8,012
Inventory holding (gains) and losses		(223)		96		(219)
Identified net (gains) losses		2,388		1,161		(1,990)
Total net non-core items in operating profit		2,165		1,257		(2,209)
Non-GAAP measure of operating profit		8,597		11,240		5,803
GAAP measure of net profit		148		4,126		3,374
Inventory holding (gains) and losses, post tax		(157)		69		(156)
Identified net (gains) losses, post tax		2,885		388		(839)
Total net non-core items in net profit		2,728		457		(995)
Non-GAAP measure of net profit		2,876		4,583		2,379

~~Hydrocarbons production was substantially stable y-o-y in spite of a 19% reduction in capital expenditures. Project re-phasing and~~In 2019, the renegotiation of contracts for the supply of plants and equipment drove the capital reduction. The Group replaced 193% of the reserves produced due to progress in development activities, exploration success and the FID taken at the Zohr gas project, off Egypt. The effectiveness of our exploration activity was proven by the finalization of the transactions to dispose of a 40% interest in the Zohr discovery, with a value to Eni of approximately €2 billion, which includes the reimbursement of the cost incurred in 2016 for developing and operating activities. Even discounting the Zohr 40% disposal, our proved reserve replacement ratio would remain significant at 139%.

In 2016, we started several new capital projects, including Goliat in the Barents Sea and Kashagan in Kazakhstan. In 2017, we expect new large field start-ups, including the OCTP oilfield in Ghana, the East Hub project in Angola, started up in February 2017, the Jangkrik gas complex in Indonesia and the Zohr project. In 2017, we forecast a production growth of approximately 5% due to the full ramp-up of fields started in 2016 and new projects coming on stream.

~~In 2016,~~Group’s net cash provided by operating activities was €12,392 million, 9% lower than in 2018, despite the trading environment was significantly worse than the previous year. The cash flow was supported by the collection of dividends from ~~continuing operations~~Eni’s joint ventures, affiliates and other minority interests (€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.

Capital expenditure and acquisitions amounted to ~~€7,673 million. The closing~~€11.384 million and comprised the purchase of a 20% interest in ADNOC Refining for a cash consideration of €2.9 billion. Capital expenditure were €8,376 million including the ~~Saipem transaction generated approximately €5.2~~purchase of proved and unproved mineral interests in Algeria and Alaska for €0.4 billion, and were mainly directed to the development of ~~proceeds~~hydrocarbons reserves and ~~was~~exploration

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~~one~~projects. We divested some minor assets for a cash-in of ~~the main drivers in the Group’s net borrowings reduction y-o-y; other disposals amounted~~€504 million. Cash returns to ~~€0.6 billion. These inflows funded part of financial requirements for capital expenditure (€9,180 million),~~shareholders were €3,424 million and included the payment of ~~Eni’s dividend (the~~the final dividend 2018, the interim 2019 dividend for ~~fiscal year 2015~~an overall amount of €3,018 million and the ~~2016 interim dividend totaling €2,881 million)~~execution of a stock repurchase plan for €400 million.

Those inflows and ~~finally~~outflows coupled with the ~~amount cashed out to subscribe~~initial recognition of the ~~share capital~~lease liabilities upon adoption of IFRS 16 effective since January 1, 2019 (see dedicated paragraph below) drove an increase of ~~Saipem (€1,069 million). Management also assessed~~€4,301 million in the Group net cash provided by operating activities excluding the negative effect of the Val d’Agri shutdown, which amounted to €0.2 billion, the reimbursement in-kind of certain financing receivables due by a joint venture to Eni with trading receivables, which negatively impacted the operating cash flow for €0.3 billion, while changes in working capital due to the sale of the 40% interest in Zohr would have improved cash flow by €0.1 billion. On that basis, net cash provided by operating activities would have funded a large part of 2016 capital expenditure of €9.2 billion, particularly when considering that approximately €0.5 billion of capex incurred in the year will be reimbursed to Eni because of the Zohr transaction in 2017. The Group’s net debt decreased by €2,095 million to €14,776 million. The Group ratio of finance debt to €30,166 million as at December 31, 2019. The ratio of indebtedness calculated based on GAAP measures was 0.63, calculated as ratio of total ~~equity at year-end 2016 was 0.51. However, in assessing~~finance debt including the lease liability to total equity.

Management evaluates the soundness of the Group balance sheet and its financial ~~structure, management is using~~position by monitoring a non-GAAP measure of indebtedness, net borrowings, which ~~subtracts~~is calculated by subtracting cash and cash equivalents and other very liquid financial assets from finance ~~debt. This Non-GAAP measure~~debt (see Glossary).

In 2019, net borrowings before the effect of IFRS 16 increased by €3.2 billion as a result of the above-mentioned cash inflows and outflows. Adding the initial recognition of the lease liabilities at the opening balance for €5,759 million following transition to IFRS 16, including the repayment of lease liabilities for €877 million and the inception of new lease contracts in the year for €766 million, net borrowings at year end climbed to €17.13 billion, compared to €8.29 billion at the end of 2018, an increase of €8,836 million (see the reconciliation table on page 96). The lease liability initially recognized included approximately €2 billion pertaining to our joint operators in Eni-led upstream projects; that amount will be recovered through a partner-billing process.

Our ratio of indebtedness ~~is defined “net borrowings” (see Glossary). The~~– leverage – ratio of net borrowings to total equity ~~is defined “Leverage” (see Glossary) and is commonly used by management in assessing~~increased to 0.36 at year-end 2019 from 0.16 at year-end 2018. Excluding the ~~Group financial condition (see~~impact of IFRS 16, leverage would have been 0.24. See paragraph “Financial condition” ~~below). Leverage at year-end 2016 decreased to 0.28 down from 0.29 at the end of 2015 and was~~ below, ~~the 0.30 threshold set by management in spite of a two-year downturn in crude oil prices.~~

In 2017, we are projecting a capital expenditure budget of approximately €7.6 billion, 18% lower than in 2016 at constant exchange rates, while confirming an increase in production by approximately 5% compared to 2016.

We also plan to preserve our liquidity by leveraging on the timely development of capital projects in the Exploration & Production in order to achieve the scheduled time-to-market of our reserves, on cost efficiencies across all businesses and on strengthening profitability at our Gas & Power and Refining & Marketing and Chemical segments. We plan to generate additional funds through our asset disposal program, which will mainly comprise the dilution of our working interests in certain of our exploration discoveries. In March 2017, we signed a preliminary agreement to divest to ExxonMobil a stake of 25% in our exploration asset Area 4 in Mozambique for a ~~cash consideration~~full reconciliation of ~~$2.8 billion.~~

~~Finally, notwithstanding a weak commodity prices environment, we are planning~~net borrowings and leverage to ~~confirm our base dividend of €0.8 per share for fiscal year 2017.~~the most comparable performance measures calculated in accordance with IFRS.

Trading environment


	2014		2015		2016		2019		2018		2017
Average price of Brent dated crude oil in U.S. dollars(1)		98.99		52.46		43.69		64.30		71.04		54.27
Average price of Brent dated crude oil in euro(2)		74.48		47.26		39.47		57.44		60.15		48.03
Average EUR/USD exchange rate(3)		1.329		1.110		1.107		1.119		1.181		1.130
Standard Eni Refining Margin (SERM)(4)		3.2		8.3		4.2		4.3		3.7		5.0
Euribor - three month euro rate %(3)		0.21		(0.02)		(0.26)

Euribor – three month euro rate % (3)								(0.36)		(0.32)		(0.33)

(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 difference between the average selling prices and reflects the trading environment and ~~are,~~is, to a certain extent, a gauge of industry profitability.

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

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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.

In ~~2016,~~ the ~~trading environment was characterized by a continued weakness in~~first quarter 2020, crude oil prices ~~particularly in first half~~have dropped materially, hitting a multi-year low below 30 $/bbl driven by the spread of ~~the year due to oversupplies. In the second half of the year, market conditions started to improve~~a pandemic disease and ~~oil prices recovered~~a seemingly changed policy on part of ~~first-half losses. This was driven by a better balance between global demand and supplies on the back~~OPEC+ from supporting prices to boost production. The impact of the agreement reached by OPEC Countries at the end of November 2016 to reduce the output of the cartel, joined also by certain non OPEC countries (among which Russia). Despite this recovery, the average price for the Brent crude oil benchmark declined by 17% y-o-y. A weak commodity scenario (mainlythese trends is described in the ~~United States and in Europe) affected gas realizations on equity production, also reflecting time lags in oil-linked price formulas.~~section “Management expectations of operations” within this item 5.

Eni’s refining margins (Standard Eni Refining Margin - SERM) that represents the benchmark for the level of profitability of Eni’s refineries before fixed cash expenses, halved from a year ago (down by 49.4%) to $4.2 per barrel due to structural headwinds in the European refining industry. The Company managed to reduce its breakeven margin and to align it with the current trading environment, exceeding the planned breakeven target of $4.5 per barrel.

Gas prices in the Company’s Gas & Power segment declined y-o-y driven by continued oversupplies, weak demand growth and the constraints connected minimum off-take obligations provided by long-term gas purchase contracts with take-or-pay clause. In addition to declining spot sale prices, in 2016 also the differential between Italian hub prices and European hub ones (PSV vs. TTF) contracted and negatively affected the G&P segment’s results.

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~~The exchange rate of euro against the dollar was 1.107, stable compared to the average exchange rate recorded in 2015.~~

Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the carrying amounts of assets and liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience or other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas assets, specifically in the determination of proved and proved developed reserves and impairment of fixed ~~assets,~~assets. Other areas where management’s estimates and judgement is applied include, among others, evaluation and recognition of intangible assets, equity-accounted investments and goodwill, decommissioning and restoration liabilities, business combinations, pensions and other post-retirement benefits, environmental liabilities and ~~recognition of environmental liabilities.~~lease contracts. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A ~~summary~~review of significant accounting estimates and judgemental areas is provided in “Item 18 – ~~note 6 – of the Notes on~~Note 1 to Consolidated Financial Statements”.

~~2014-2016 Group results~~IFRS 16 adoption

Eni’s 2019 consolidated financial statements and the statements of ~~operations~~

~~Adoption~~profit and loss, cash flow and financial position commented in this Item 5 have been prepared incorporating the effects of the ~~Successful effort method (SEM)~~

~~Effective~~new IFRS 16 “Leases”, effective at the beginning of the year, which defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration and eliminates the classification of leases as either operating leases or finance leases for the preparation of the lessee’s financial statements. The Group is hiring third-party assets in the connection with operating activities and the execution of capital projects; these assets mainly comprise FPSO vessels, drilling rigs, buildings, service stations and logistic facilities. The standard provides a lessee to recognize a right-of-use asset, that represents a lessee’s right to use an underlying asset (ROU), and a corresponding finance liability, the lease liability (LL) that represents the lessee’s obligation to make the contractual lease payments recorded at their present value. The new accounting standard has determined a significant impact on the Group key performance indicators of its consolidated financial statements, particularly in net borrowings, with a step up effect due to the fact that Eni has adopted the modified retrospective approach by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance at January 1, ~~2016, management elected~~2019, without restating the comparative periods. Additional information about adoption of IFRS 16 with regard to ~~change~~assumptions and practical expedients used in the ~~criterion~~first application are provided in the notes to ~~recognize exploration expenses adopting~~ the ~~successful-effort-method (SEM)~~consolidated financial statements under the heading “changes to accounting criteria”. ~~The successful-effort method is largely adopted by oil&gas companies, to which Eni is increasingly comparable given the recent re-focalization~~A brief description of the ~~Group activities~~new accounting for lease contracts under IFRS 16 and the main effects on ~~its core upstream business.~~the 2019 financial statements are provided below:

- in the profit and loss account, depreciation charges of the ROU asset and interest expense accrued on the LL are recognized within operating expenses and finance expense, respectively. Under the ~~SEM, geological~~previous accounting standard, operating lease payments were recorded within operating expenses. The following table shows certain profit and ~~geophysical exploration costs are~~loss items as adjusted to exclude the effect of the application of IFRS 16 and a reconciliation to the reported measure in compliance with IFRS.

Profit and loss account 2019

(€ 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

- in the statement of cash flows, reimbursement of the principal portion of the LL is recorded as part of financing activities. Interest expense is recorded as part of operating activities, or as part of investing activities depending on whether it is recognized asin the profit and loss account or is being capitalized in relation to the hire of equipment used in connection with capital projects. Consequently, compared with the requirements of the previous accounting standard in force, IAS 17 related to operating leases, the adoption of IFRS 16 determined a significant impact in the statement of cash flows due to: (a) an ~~expense as incurred. Costs directly associated with an exploration well are initially capitalized as an unproved tangible~~improvement in

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~~asset until~~net cash provided by operating activities, which no longer includes the ~~drilling~~operating lease payments related to assets hired in connection with operating activities, but only includes the cash payments for the interest portion of the ~~well is completed and~~LL relating to those assets; (b) an improvement in net cash used in investing activities, which no longer includes capitalized lease payments in connection with assets hired in connection with a capital project, but only includes cash payments for the results have been evaluated. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an unproved asset. If it is determined that development will not occur then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons are initially capitalized as an unproved tangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to proved property.

~~In accordance to IAS 8 “Accounting policies, Changes in accounting estimates and Errors”, the retrospective application~~interest portion of the ~~SEM has required adjustment~~lease liability relating to those assets; and (c) an increase in the net cash used in financing activities, which includes cash payments for the principal portion of the ~~opening balance of several~~LL. The following table shows certain cash flow statement items as ~~of January 1, 2014. Specifically,~~adjusted to exclude the ~~opening balance~~effect of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items.

~~In the table below, the key line items of the profit and loss and balance sheet are presented with reference to the full years 2014 and 2015 previously reported, and as restated in accordance with~~ the application of ~~SEM~~IFRS 16 and a reconciliation to the ~~cessation~~reported measure in compliance with IFRS.

Cash flow statement 2019

(€ million)	before IFRS 16		IFRS 16 effects		GAAP results
Net cash provided by operating activities		11,726		666		12,392
Capital expenditure		(8,587)		211		(8,376)
Cash flow from financing activity		(4,964)		(877)		(5,841)
Net increase (decrease) in cash and cash equivalent		(4,861)				(4,861)
Initial adoption of IFRS 16				(5,759)		(5,759)
New LL for the year				(766)		(766)
LL reimbursement in the year				877
Change in net borrowings(a)		(3,188)		(5,648)		(8,836)

(a)

Net borrowings is a Non-GAAP measure of indebtedness. For a reconciliation of net borrowings to finance debt see page 108 “Financial condition”.

The initial adoption of IFRS 16 resulted in a €5.76 billion increase in net borrowings due to the initial recognition of the ~~accounting~~LL in the opening balance. However, the initial amount of Eni’s ~~Chemical segment as~~LL is affected by the fact that in the E&P sectors oil&gas projects are carried out based on the contractual scheme of unincorporated joint operations managed by one of the joint operators (the lead operator). This structure entails that the LL relating to lease contracts entered into by the lead operator on behalf of the joint operations is recorded in full in the financial statements of the lead operator, because the lead operator is normally the sole signatory of the lease contract and consequently takes primary responsibility for discharging the lease obligations towards the third-party lessor, notwithstanding the fact that the lead operator is able to recover the share of lease payments attributable to the joint operators through a ~~disposal group held for sale. In 2015,~~partner billing process. As a result, the ~~Chemical segment was presented as discontinued operations due to an ongoing negotiation at~~ROU of the ~~2015~~asset utilized by a joint operation is recorded in its full amount in the balance sheet ~~date designed to establish an industrial joint venture with a third party who had expressed an interest in acquiring a majority stake~~ of ~~Eni’s chemical arm. In 2016 Eni and~~ the ~~potential buyer could not come to an agreement and the accounting of Versalis as discontinued operation ceased with retroactive effects to the date of initial recognition as discontinued operations.~~lead operator.

AS
PREVIOUSLY
REPORTED AS
RESTATED
(€ million)
Full year 2014
Operating profit (loss) - continuing operations 7,585 8,965
Operating profit (loss) E&P 10,766 10,727
Net profit (loss) attributable to Eni’s shareholders - continuing operations 101 1,720
Total assets 146,207 150,366
Eni’s shareholders equity 59,754 63,186
Net cash flow 1,183 1,183

Full year 2015
Operating profit (loss) - continuing operations (2,781) (3,076)
Operating profit (loss) E&P (144) (959)
Net profit (loss) attributable to Eni’s shareholders - continuing operations (7,680) (7,952)
Total assets 134,792 139,001
Eni’s shareholders equity 51,753 55,493
Net cash flow (1,414) (1,405)

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~~Overview~~Group results of ~~the profit and loss account for three years ended December 31, 2014, 2015 and 2016~~operations

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

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(€ million)						(€ million)
Net sales from operations		98,218		72,286		55,762
Sales from operations								69,881		75,822		66,919
Other income and revenues(1)		1,079		1,252		931		1,160		1,116		4,058
Total revenues		99,297		73,538		56,693		71,041		76,938		70,977
Operating expenses		(80,333)		(59,967)		(47,118)		(54,302)		(59,130)		(55,412)
Other operating (expense) income		145		(485)		16		287		129		(32)
Depreciation, depletion and amortization		(7,676)		(8,940)		(7,559)		(8,106)		(6,988)		(7,483)
Impairment losses (impairment reversal), net		(1,270)		(6,534)		475
Write-off		(1,198)		(688)		(350)
Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net								(2,188)		(866)		225
Write-off of tangible and intangible assets								(300)		(100)		(263)
OPERATING PROFIT (LOSS)		8,965		(3,076)		2,157		6,432		9,983		8,012
Finance income (expense)		(1,167)		(1,306)		(885)		(879)		(971)		(1,236)
Income (expense) from investments		476		105		(380)		193		1,095		68
PROFIT (LOSS) BEFORE INCOME TAXES		8,274		(4,277)		892		5,746		10,107		6,844
Income taxes		(6,466)		(3,122)		(1,936)		(5,591)		(5,970)		(3,467)
Net profit (loss) - continuing operations		1,808		(7,399)		(1,044)
Net profit (loss) - discontinued operations		(949)		(1,974)		(413)
Net profit (loss)		859		(9,373)		(1,457)		155		4,137		3,377
Attributable to:
Eni’s shareholders:		1,303		(8,778)		(1,464)
- continuing operations		1,720		(7,952)		(1,051)
- discontinued operations		(417)		(826)		(413)
Non-controlling interest:		(444)		(595)		7
- continuing operations		88		553		7
- discontinued operations		(532)		(1,148)

- Eni’s shareholders								148		4,126		3,374
- Non-controlling interest								7		11		3

(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 ~~net~~ sales from operations for the periods indicated.

Year ended December 31,
2014 2015 2016
(%)
Operating expenses 81.8 83.0 84.5
Depreciation, depletion, amortization, impairments (reversal of assets) net, write-off 10.3 22.4 13.3
OPERATING PROFIT 9.1 �� (4.3) 3.9

~~2016 compared to 2015. See management discussion under paragraph “Executive summary” on page 90 for an overview of the Group’s results from continuing operations.~~

Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €1,464 million for 2016. The loss of the discontinued operations pertaining to Eni’s shareholders (€413 million) was affected by the recognition of a charge of €441 million due to the

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alignment of Eni’s retained interest in Saipem with its market value the date of the loss of control (January 22, 2016). The market value of the retained interest in the former subsidiary was the carrying amount of such interest upon initial recognition for the subsequent accounting under the equity method (€564 million to which a share capital increase of €1,069 million is to be added).

~~2015 compared to 2014~~. Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €8,778 million for 2015. The loss of the discontinued operations pertaining to Eni’s shareholders was negatively affected by the recognition of an impairment loss on the disposal group Saipem the net assets of which were aligned to the lower of their carrying amounts and fair value. Eni’s net asset in Saipem were aligned to the share price at the reporting date, recording an impairment charge of €393 million. Partly offsetting, a fair-valued derivative gain of €49 million was recorded for Saipem due to the difference between the transaction price (€8.39 per share) and the market price at the reporting date (€7.49 per share) relating the stake under disposal.

~~Discontinued operations~~

~~The table below sets forth net profit (loss) attributable to discontinued operations for the periods indicated.~~

Year ended December 31,
2014 2015 2016
(€ million)
Net profit - discontinued operations (949) (1,974) (413)
attributable to:
- Eni (417) (826) (413)
- non-controlling interest (532) (1,148)

Based on the accounting of IFRS 5 for disposal groups, gains and losses pertaining to the discontinued operations include only those earned from transactions with third parties. Until such time as Saipem was a subsidiary of the Eni Group (i.e. end of the reporting period 2015), gains and losses on intercompany transactions have been eliminated upon consolidation. These comprised mainly revenues earned by Saipem for the supply of capital goods and maintenance services to Eni’s Group companies, which were eliminated upon consolidation, positively affecting results of the continuing operations, while negatively affecting the results of operations of the discontinued operations. This effect did not recur in 2016 due to the derecognition of Saipem effective January 1, 2016. Furthermore, the 2015 loss from discontinued operations included the alignment of Saipem’s net assets to its market capitalization at the balance sheet date leading to a loss of €393 million.

	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 and loss account ~~of continuing operations~~

a) Total revenues

Eni’s revenues ~~from continuing operations~~ were ~~€56,693 million, €73,538~~€71,041 million and ~~€99,297~~€76,938 million for the years ended December 31, ~~2016, 2015~~2019 and ~~2014,~~2018, respectively. Total revenues consist of ~~net~~ sales from operations and other income and revenues. ~~Eni’s net~~Eni sales from operations ~~from continuing operations~~ amounted to ~~€55,762 million, €72,286~~€69,881 million and ~~€98,218~~€75,822 million for the ~~year~~years ended December 31, ~~2016, 2015~~2019 and ~~2014,~~2018, respectively, and its other income and revenues totaled ~~€931 million, €1,252~~€1,160 million and ~~€1,079~~€1,116 million, respectively, in these periods.

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~~Net sales~~Sales from ~~operations from continuing~~ operations

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

Year ended December 31,
2014 2015 2016
(€ million)
Exploration & Production 28,488 21,436 16,089
Gas & Power 73,434 52,096 40,961
Refining & Marketing and Chemicals 28,994 22,639 18,733
Corporate and other activities 1,429 1,468 1,343
Impact of unrealized intragroup profit elimination(1)
54
Consolidation adjustment(2)
(34,181) (25,353) (21,364)
NET SALES FROM OPERATIONS 98,218 72,286 55,762

~~(1)~~

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

~~(2)~~

Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The largest intragroup sales are recorded by the Exploration & Production segment. “Item 18 – note 46 – of the Notes on Consolidated Financial Statements” for a breakdown of intragroup sales by segment for the reported years.

	Year ended December 31,
	2019		2018		2017
	(€ million)
Exploration & Production		23,572		25,744		19,525
Gas & Power		50,015		55,690		50,623
Refining & Marketing and Chemicals		23,334		25,216		22,107
Corporate and other activities		1,681		1,589		1,462
Consolidation adjustments		(28,721)		(32,417)		(26,798)
SALES FROM OPERATIONS		69,881		75,822		66,919

~~2016~~2019 compared to ~~2015~~2018. ~~Eni’s net~~Eni sales from operations (revenues) ~~from continuing operations~~ for ~~2016~~2019 (€~~55,762~~69,881 million) decreased by ~~€16,524~~€5,941 million from ~~2015~~2018 (or down ~~22.9%~~by 7.8%) primarily reflecting ~~lower realizations on oil, products and natural gas due to significantly lower~~a slowdown in commodity prices. ~~Changes in sales volumes of products sold were immaterial.~~

Revenues generated by the Exploration & Production segment (€~~16,089~~23,572 million) decreased by ~~€5,347~~€2,172 million (or down by ~~24.9%~~8.4%). This was due to lower average realizations on equity hydrocarbons ~~(down~~(oil realizations down by ~~20.1%~~9.5%; gas realizations down by 5% on average in dollar terms) driven by ~~declining~~lower prices for the marker Brent (down by ~~16,7%~~9.5%) and gas ~~benchmarks~~prices in ~~Europe,~~Europe. Furthermore, lower benchmark gas prices negatively affected the revenues earned from reselling the gas volumes entitlements of a Libyan partner in the ~~United States and elsewhere also considering the time lags in oil-linked formulas. The reduction~~European market. Finally, y-o-y comparability was ~~also~~ negatively affected by the ~~Val d’Agri shutdown, which lasted four and half months. The negative price impact was mainly recorded~~de-recognition of our former subsidiary Eni Norge at ~~concession contracts, while PSA contracts are insulated from~~ the ~~scenario due~~end of 2018, following a business combination with the Norwegian company Point Resources to established the ~~cost recovery mechanism.~~Vår Energi joint-venture (Eni’s share 69.6%).

Revenues generated by the Gas & Power segment (€~~40,961~~50,015 million) decreased by ~~€11,135~~€5,675 million (or down by ~~21.4%~~10.2%). The ~~reduction~~decrease reflected lower natural gas ~~and power selling prices as well as lower commodity~~ prices in ~~the business of crude oil~~Europe and ~~refined products trading, which impact was however offset at the operating profit level by~~declining LNG prices due to a ~~corresponding decrease in the supply costs of the commodities. Furthermore, revenues were also negatively affected by a downward revision of revenues accrued on the sale of gas~~weaker Asian scenario and ~~power to retail customers in Italy (€161 million) dating back to past reporting periods prior to 2015.~~lower volumes sold.

Revenues generated by the Refining & Marketing and Chemical segment (€~~18,733~~23,334 million) decreased by ~~€3,906~~€1,882 million (or down by ~~17.3%~~7.5%) ~~mainly reflecting~~due to lower average selling prices ~~driven by weaker commodity prices. The~~of gasoline and gasoil in the Refining & Marketing business, as well as the decline in average selling prices and lower volumes sold, mainly intermediates, in the Chemical business ~~declined by 10% due to lower price of polymers (down by 6.7% and down by 6.3% the average price of elastomers and styrenics, respectively), reflecting the impact of scenario and competitive pressure.~~

~~2015 compared to 2014~~. Eni’s net sales from operations (revenues) from continuing operations for 2015 (€72,286 million) decreased by €25,932 million from 2014 (or down by 26.4%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms due to significantly lower commodity prices. This negative trend was partially offset by a favorable exchange rate environment and increased sales volumes in the Exploration & Production segment, as well as higher Eni’s refining throughputs.

Revenues generated by the Exploration & Production segment (€21,436 million) decreased by €7,052 million (or down by 24.8%) due to lower oil&gas realizations in dollar terms (down by 44.3% on average) reflecting the lower price for the marker Brent and lower gas prices in Europe and in the United States.

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Lowered hydrocarbons realizations in dollars reduced reported revenues by approximately €12 billion. This effect was partly offset by favorable exchange rate differences in translating dollar-denominated revenues into the euro representation currency for €3.3 billion and higher production volumes sold for €1.6 billion. The negative price impact was mainly recorded at concession contracts, while PSA contracts are insulated from the scenario due to the cost recovery mechanism.

Revenues generated by the Gas & Power segment (€52,096 million) decreased by €21,338 million (or down by 29.1%). The reduction reflected lower commodity prices in the business of crude oil and refined products trading, which impact was however offset by a corresponding decrease in the supply costs of the commodities. Furthermore, gas selling prices continued to deteriorate reflecting, in addition to the commodity price environment, weak gas demand and increasing competitive pressure. Revenues were also impacted an estimate revision of revenues accrued on the sale of gas (€346 million) and power (€138 million) to retail customers in Italy dating back to the past reporting periods.

~~Revenues generated by the Refining & Marketing and Chemicals segment (€22,639 million) decreased by €6,355 million (or down by 21.9%) mainly reflecting lower average sales prices products~~ driven by lower ~~commodity prices.~~demand and plant incidents and outages.

Other income and revenues

2019 compared to 2018. Eni’s other income and revenues amounted to €1,160 million in 2019 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 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,
	2014		2015		2016		2019		2018		2017
	(€ million)						(€ million)
Purchases, services and other		77,404		56,848		44,124		50,874		55,622		51,548
Impairment losses (impairment reversals) of trade and other receivables, net								432		415		913
Payroll and related costs		2,929		3,119		2,994		2,996		3,093		2,951
Operating expenses		80,333		59,967		47,118		54,302		59,130		55,412

~~2016~~2019 compared to ~~2015~~2018. Operating expenses ~~from continuing operations~~ for ~~2016~~2019 (€~~47,118~~54,302 million) decreased by ~~€12,849~~€4,828 million y-o-y, down by ~~21.4%~~8%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale). Purchases, services and other costs included €360 million relating mainly to environmental provisions ((€436 million in 2015). Payroll and related costs (€2,994 million) decreased by €125 million from 2015, down by 4%,resale due to lower ~~average number of employees outside Italy.~~

~~2015 compared to 2014~~. Operating expenses from continuing operations for 2015 (€59,967 million) decreased by €20,366 million from 2014, down by 25.4%, primarily reflecting lower supply costs of raw materials (natural gas under long-term contracts, refinery feedstock and hydrocarbons purchased for resale) due to underlying trends in the energy scenario partially offset by negative exchange rate effects. Purchases, services and other costs included €436 million relating to environmental and other risk provisions, net of reversal of unused provisions. In addition, an allowance to the provision for doubtful accounts was recognized in 2015 in the retail Gas & Power business to take in account an estimate revision of revenues accrued on the sale of natural gas and electricity (€226 million; €130 million for gas sale and €96 million for electricity) to retail customers in Italy dating back to past reporting periods. Payroll and related costs (€3,119 million) increased by €190 million from 2014, up by 6.5%, due to the appreciation of the U.S. dollar against the euro. These effects were partially offset by lower average number of employees.

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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, ~~impairments (impairments reversal)~~impairment losses (impairment reversals) net and write-off

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

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(€ million)						(€ million)
Exploration & Production		6,916		8,080		6,772		7,060		6,152		6,747
Gas & Power		335		363		354		447		408		345
Refining & Marketing and Chemicals		381		454		389		485		399		360
Corporate and other activities		70		71		72		146		59		60
Impact of unrealized intragroup profit elimination(1)		(26)		(28)		(28)		(32)		(30)		(29)
Total depreciation, depletion and amortization		7,676		8,940		7,559		8,106		6,988		7,483
Impairment losses		1,334		6,537		1,067
Reversals of impairment losses		(64)		(3)		(1,542)
Write-off		1,198		688		350
Total depreciation, depletion, amortization, impairment losses (impairment reversals), net and write off		10,144		16,162		7,434

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 ~~assests~~assets of the purchasing business segment.

~~2016~~2019 compared to ~~2015~~2018. In ~~2016,~~2019, depreciation, depletion and amortization charges (€~~7,559~~8,106 million) ~~decreased~~increased by ~~€1,381~~€1,118 million from ~~2015,~~2018, or ~~15.4%~~16%, mainly in the Exploration & Production segment ~~(with a decrease~~(an increase of ~~€1,308~~€908 million) ~~reflecting lower capital expenditures~~mainly due to the depreciation charges of the ~~year (down by 16.2%)~~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 to lower interest rates, as well as fields started-up and ~~the lower carrying amounts of certain oil&gas properties following the impairment losses booked in 2015 (€5,212 million).~~new projects ramp-up.

In ~~2016,~~2019, the Group recorded ~~reversals of prior~~ impairment losses at ~~oil&gas properties~~property, plant and equipment for ~~€1,440 million. These were determined by an upward revision to the long-term price~~a total amount of the benchmark Brent to 70 $/barrel, up from the previous 65 $/barrel assumption, which drove the financial projections of the 2017-2020 industrial plan and the recoverability of oil&gas assets carrying amounts in the 2016 financial statements. These reversals were partly offset by€2,188 million, mainly relating to: (i) impairment losses ~~related to gas properties in the upstream business driven by a lowered price outlook in Europe and other~~of oil&gas properties due to ~~contractual changes,~~downward reserves ~~revision~~revisions and ~~a higher country risk (overall~~lower-than-expected performance at certain fields in Congo, Italy and in the USA, and of certain assets to align the book value to fair value (for an overall amount of ~~€756~~€1,217 million)~~. Finally, investments made for compliance and stay-in-business purposes were fully impaired at cash generating units previously written-off in~~; (ii) impairment losses recorded by the Refining & Marketing business, mainly at the Sannazzaro refinery, reflecting a revised margin outlook both at high and ~~Chemicals segment, which~~low-complexity cycles, upward revisions 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 ~~confirmed~~impaired in previous reporting periods and continued to lack any profitability prospects (for an overall impact of €819 million); (iii) impairment losses of Chemical assets due to a lowered profitability outlook (€~~104 million), while~~103 million in the ~~Gas&Power segment recorded €81~~full year).

Write-off charges amounted to €300 million and related to ~~a gas transport infrastructure and LNG carriers.~~

~~The write-off amounting to €350 million, mainly related to the~~previously capitalized costs of exploratory wells ~~lacking the requisites for continuing capitalization~~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. The item also comprised the write-off of the damaged units of the EST conversion plant at the Sannazzaro Refinery due to the accident occurred~~commitment in ~~December 2016 (€193 million).~~

~~2015 compared to 2014. In 2015, depreciation, depletion and amortization charges (€8,940 million) increased by €1,264 million from 2014, or 16.5%,~~pursuing further appraisal activity mainly in ~~the Exploration & Production segment (increasing by €1,164 million) reflecting the appreciation of the U.S. dollar against the euro~~Australia, Kazakhstan and ~~higher production volumes.~~

In 2015, impairment charges of €6,534 million related to oil&gas properties (€5,212 million) driven by the projections of lower hydrocarbon prices in the medium to long-term, which affected their recoverable amounts. The most notable impairments refer to certain assets, which were acquired by the Group following business combinations in previous reporting periods (Algeria, Congo and Turkmenistan) and to CGUs which are currently operating in high-cost areas (United States, United Kingdom, Norway and Angola). Furthermore, investments made for compliance and stay-in-business purposes were written off atPakistan.

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cash generating units previously written-off in the Refining & Marketing and Chemicals segment, which were confirmed to be lacking any prospects of profitability. Finally, impairment losses were recorded at the Group power plants in the G&P segment due to a weak margins scenario. The amount of write-offs of exploration project was also mainly driven by management’s decision to cease committing funds to certain projects in light of the deteriorated oil price environment.

d) Operating profit (loss) by segment

The table below sets forth Eni’s operating profit ~~from continuing operations~~ by business segment for the periods indicated.

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(€ million)						(€ million)
Exploration & Production		10,727		(959)		2,567		7,417		10,214		7,651
Gas & Power		64		(1,258)		(391)		699		629		75
Refining & Marketing and Chemicals		(2,811)		(1,567)		723		(854)		(380)		981
Corporate and other activities		(518)		(497)		(681)		(710)		(691)		(668)
Impact of unrealized intragroup profit elimination		1,503		1,205		(61)		(120)		211		(27)
Operating profit (loss)		8,965		(3,076)		2,157		6,432		9,983		8,012

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

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(%)						(%)
Exploration & Production		37.7		(4.5)		16.0		31.5		39.7		39.2
Gas & Power		0.1		(2.4)		(1.0)		1.4		1.1		0.1
Refining & Marketing and Chemicals		(9.7)		(6.9)		3.9		(3.7)		(1.5)		4.4
Group		9.1		(4.3)		3.9		9.2		13.2		12.0

Exploration & ~~Production~~Production.. In ~~2016,~~2019, the Exploration & Production segment reported an operating profit of ~~€2,567~~€7,417 million, with ~~an increase~~a decrease of ~~€3,526~~€2,797 million ~~from~~compared to the operating ~~loss~~profit of ~~€959~~€10,214 million reported in ~~2015. This change mainly reflected~~2018. The decline was driven by lower realized prices on equity hydrocarbons, particularly lower gas prices in Europe, a loss incurred in connection with the reselling of volumes of gas entitlements of a Libyan partner, and higher amortization charges, exploration well write-offs and impairment ~~charges~~losses taken at oil&gas properties, partly offset by production growth and a better volume/mix performance reflecting higher contribution of ~~€5,212 million recorded in 2015 due to a downward revision~~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 ~~oil scenario, while~~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 ~~2016 net impairment reversals of €684 million were recorded due to a hike~~production for 2019 is provided in ~~management long-term oil price assumptions.~~the section “Executive summary”.

In ~~2016,~~2019, the Company’s liquids and gas realizations decreased on average by ~~20.1%~~8.3% in dollar terms, driven by a ~~decline in international oil prices for market benchmarks (Brent crude prices decreased by 16.7%).~~weak trading environment. Eni’s average oil realizations decreased on average by ~~15.4%~~9.5%, in line with the decrease recorded in international oil prices for the Brent market benchmark (down by 9.5% for the year). Eni’s average gas realizations decreased by ~~28.2% and were negatively impacted by the weak scenario and time lags in oil-linked formulas.~~

In 2015, the Exploration & Production segment reported an operating loss of €959 million, with a decrease of €11,686 million from 2014. The decline was principally due to reduced oil&gas realizations in dollar terms (down 44.3% on average) and increased impairment charges (up by €4,361 million)5%. The ~~negative impacts~~decrease in gas realization prices did not take into account the lower prices realized on the reselling of volumes of gas entitlements of a Libyan partner, which were ~~only partially offset by a favorable exchange rate environment, higher production volumes and reduced operating expenses.~~

~~In 2015, the Company’s liquids and gas realizations decreased on average by 44.3%~~marketed in ~~dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude price decreased by 47%).~~Europe, because Eni’s average ~~oil realizations decreased on average by 47.8%. Eni’s average~~realized gas ~~realizations decreased by 33.8%.~~prices are calculated only with reference to equity production.

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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. ~~Excluding the below-listed~~In 2019, non-core gains and losses included impairment charges of oil&gas assets (€1,217 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 million) and included the gain on the assets disposal (€145 million) mainly related to the disposal of the 20% interest in the Merakes discoveries to Neptune.

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Excluding those items, the E&P segment reported a Non-GAAP operating profit of ~~€2,494~~€8,640 million, with a decrease of ~~€1,688~~€2,210 million from ~~2015, or 40.4%. The decrease was~~2018, down by 20.4%, driven byby: (i) a ~~weak commodity~~negative impact of the trading environment ~~which drove reduced oil&gas realizations in dollar terms (down by 20.1% on average) and~~(€2.23 billion) mainly due lower prices of equity gas as well as a ~~four-month and half production shutdown~~loss incurred at the ~~Val d’Agri site.~~ reselling of volumes of gas entitlements of a Libyan partner due 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 profit (€200 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 ~~negatives~~negative trends were partly offset by ~~higher production in other areas and lower operating expenses and DD&A~~an improved performance driven by ~~continuing efficiency initiatives~~production growth and ~~optimization, as well as lower carrying amounts~~a better volume/mix performance reflecting higher contribution of ~~oil&gas assets~~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%.

Operating profit included the revenues relating to certain gas volumes which were paid by the buyer without lifting the underlying volume due to the ~~impairments recorded~~take-or-pay clause provided in ~~2015.~~

Year ended December 31,
2014 2015 2016
Exploration & Production (€ million)
GAAP operating profit (loss) 10,727 (959) 2,567
Impairment losses (impairment reversals), net 853 5,212 (684)
Risk provisions (5) 0 105
Impairment of exploration projects(1)
169 7
Net gains on disposal of assets (70) (403) (2)
Provision for redundancy incentives 24 15 24
Fair value gains/losses on commodity derivatives (28) 12 19
Reclassification of currency derivatives and translation effects to management measure of business performance 6 (59) (3)
Valuation allowance of disputed receivables 410
Other 172 195 51
Total gains and charges 952 5,141 (73)
Non-GAAP operating profit (loss) 11,679 4,182 2,494

~~(1)~~

a long-term supply agreement. Management has ~~separately disclosed~~ascertained that it is highly likely that the ~~results of~~buyer will not redeem its contractual right to lift the ~~impairment review conducted at certain ongoing exploration projects where management ceased its commitment due to a deteriorated commodity~~pre-paid volumes in future reporting periods within the contractual terms. Therefore the price ~~environment.~~paid by the buyer was recognized as revenue.

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

Gas & Power. This segment comprises the wholesale business of gas, power and LNG, and the marketing of energy commodities (mainly gas and power) to retail customers. In ~~2016,~~2019, the Gas & Power segment reported an operating ~~loss~~profit of ~~€391~~€699 million, ~~improving by €867~~an increase of €70 million compared to ~~2015 when~~ the ~~segment reported an operating loss~~profit of €1,258 million. The 2015 result was negatively affected by a downward estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). In 2016, accrued revenues were revised lower by €161 million relating reporting periods prior to 2015. Furthermore, commodity derivatives lacking criteria for being accounted as hedges generated approximately €500€629 million of ~~higher gains in 2016.~~

~~In 2015,~~ the ~~Gas & Power segment reported an operating loss~~previous year, mainly due to a better performance of €1,258 million, down by €1,322 million from 2014 when the segment reported an operating profit of €64 million. The change reflected one-off gains associated to certain contracts renegotiation recorded in 2014, as well as the negative outcome of a commercial arbitration in 2015. Furthermore, the 2015 result was affected by an estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). Management estimates revenues accrued in the retail sales business utilizing data communicated by market operators that are responsible for verifying actual consumptions with the possibility to review their measurements until the fifth subsequent reporting period.business.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating loss of €390 million, with a decline of €264 million from 2015. This negative trend was due to lower margins in the LNG business on sales to premium markets and lower one-off benefits from contracts renegotiations, partly offset by logistics costs optimizations and better performance in trading activities. The retail segment reported lower results due to unusual winter weather conditions.

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The items excluded from GAAP operating profit in determining the Non-GAAP measure of profitability mainly include ~~certain~~effects associated with commodity fair-valued ~~derivatives and accruals measurements.~~ 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 it 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 ~~Group~~ exposure to commodities and exchange rates 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 identify the ~~fair value~~accounting effects of fair-valued derivatives used to hedge exposure to commodities and exchange rates, which lack the formal criteria to be accounted for as hedges or are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well

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as the accounting effects of commodity and exchange rates derivatives ~~because they~~which relate to transactions that will close in subsequent reporting periods or we estimate the portion of gains and losses on the settlement of certain commodity derivatives ~~which~~where underlying physical transaction has yet to be settled with the delivery of the underlying commodity. Furthermore, ~~albeit~~although the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivable and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and ~~alignment~~currency differences ofat our dollar-denominated trade payables and receivables as part of the underlying business performance. ~~Finally, management has excluded from GAAP~~

Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating profit ~~the remeasurement~~ of ~~revenues accrued~~€654 million, with an increase of €111 million from 2018. The Gas & LNG Marketing and Power segment reported a Non-GAAP operating profit of €376 million (€342 million in 2018); the retail business reported an operating profit of €278 million (€201 million in 2018).

This improvement was driven by optimizations at the gas and power assets portfolio in Europe which enabled the business ~~because they relate~~ to ~~past reporting periods.~~capture the upsides associated with a highly-volatile environment. The improved 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 in Asia which affected margins and volumes.

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
Gas & Power	(€ million)
Gas & Power							(€ million)
GAAP operating profit (loss)		64		(1,258)		(391)		699		629		75
(Profit) loss on inventory		(119)		132		90
Impairment losses		25		152		81
Risk provisions		(42)
Allowance for doubtful accruals in the retail G&P				226		17
Impairment losses (impairment reversals), net								37		(71)		(146)
Environmental provisions										(1)
Provision for redundancy incentives		9		6		4		4		122		38
Fair value gains/losses on commodity derivatives		(38)		90		(443)		(423)		(156)		157
Reclassification of currency derivatives and translation effects to management measure of business performance		205		(9)		(19)		92		112		(171)
Revision of estimate revenues accruals in the retail G&P				484		161
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		64		51		110		245		(92)		(26)
Total gains and charges		104		1,132		1		(45)		(86)		139
Non-GAAP operating profit (loss)		168		(126)		(390)		654		543		214

of which:
– Gas & LNG Marketing and Power								376		342		77
– retail business								278		201		137

Refining & Marketing and ~~Chemicals~~Chemicals.. In 2016, the Refining & Marketing and Chemicals segment reported an operating profit of €723 million, reversing an operating loss of €1,567 million reported in 2015. The improvement of €2,290 million was mainly due to lower assets impairments because a €1 billion charge was recognized in 2015 at the Chemical business to align its carrying amount with the expected fair value based on a sale transaction then ongoing designed to establish an industrial joint venture. Furthermore, in 2015 an inventory write-down of €877 million (pre-tax) was accounted for in the profit and loss because of the fall in oil commodity prices to align the net realizable value of the inventories to prices current at the balance sheet date. In 2016, following a late-year recovery in price scenario, the write down resulted in a gain on stock. The 2016 operating profit in the Refining & Marketing and Chemicals segment was also negatively affected by the write-off related to the EST conversion plant, at Sannazzaro Refinery, following an event occurred in December 2016, and the provision for removal and clean-up (a total amount of €217 million), partially offset by the recognition of third-party insurance compensation (€122 million)

~~In 2015,~~2019, the Refining & Marketing and Chemicals segment reported an operating loss of ~~€1,567 million, thereby reducing operating losses by €1,244~~€854 million, compared to ~~2014, when this segment reported~~ an operating loss of ~~€2,811 million. The losses~~€380 million reported in ~~2014~~2018 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 in ~~2015 were due to inventory write-down of €1,746 million (pre-tax) in 2014, and of €877 million in 2015, as a consequence of~~ the ~~fall in commodity prices. Both losses included a charge to align the net~~ book value of inventories ~~to their net realizable values at~~accounted for under the ~~reporting date, as well as the difference between the current~~weighted-average cost method of ~~supplies and the one used for IFRS inventory accounting based on the weighted average cost.~~

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Results in 2015 improved compared to 2014 also for a positive refining scenario. The Eni benchmark for refining margins (Standard Eni Refining Margin – SERM) improved from 3.2 $/BBL to 8.3 $/BBL. Results benefited from initiatives to optimize operations, to reduce costs and to improve energy efficiency.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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period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies.

In addition to the inventory holding loss, the non-core items of this segment for the year 2019 also comprised (i) significant impairment losses recorded at the Sannazzaro refinery, reflecting a revised margin outlook both at high and low-complexity cycles and higher projected expenses for emission allowances, as well as the write-down of capital expenditure relating to certain Cash Generating Units in the R&M business impaired in previous reporting periods, which continued lacking profitability prospects (€819 million); (ii) impairment losses of Chemical assets due to a lowered profitability outlook (€103 million); (iii) environmental provisions (€244 million), partly offset by (iv) insurance compensation (€88 million) relating to an incident occurred at the EST plant at the Sannazzaro refinery in previous reporting periods.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the inventory holding gain (or loss) and the other non-core gains and losses ~~presented below~~described above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding ~~the below-listed gains and charges, the~~those items, R&M ~~and Chemical segment~~business reported a Non-GAAP operating profit of ~~€583~~€220 million ~~with~~(€390 million in 2018) while the Chemical business reported a ~~reduction~~Non-GAAP operating loss of ~~€112~~€268 million ~~from 2015.~~ (a loss of €10 million in 2018).

The ~~segment base performance in 2016~~refining activity was negatively affected by ~~an unfavorable margin scenario, as the Eni benchmark for~~lower refining margins ~~the Standard Eni Refining Margin – SERM was down by 49%, from 8.3 $/BBL in 2015~~mainly due to ~~4.2 $/BBL in 2016. Other negative drivers were a planned shutdown of the Livorno refinery for extensive maintenance~~narrowing price differentials between heavy crudes and the ~~shutdown~~Brent market benchmark which impaired the profitability of ~~EST~~Eni’s complex refineries, as well as by lower products spreads, particularly lubricants and by longer and unplanned plant upset and outages. Marketing activities reported an improved performance both in the retail and wholesale segments also leveraging on effective commercial initiatives to support margins and on efficiency actions.

The Chemical business reported an adjusted operating loss of €268 million in 2019, a significant decline from 2018 when the segment almost achieved breakeven. The result was affected by the worsening trading environment due to a slowdown in demand at the ~~Sannazzaro refinery due to~~main end-markets, particularly the ~~accident~~automotive sector, and by weaker demand of single-use plastics pressured 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 between 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 ~~beginning~~Priolo hub, which was fully operational by the end of ~~December 2016. Moreover, marketing recorded lower results reflecting weaker margins due to stronger competitive pressure~~July, and ~~asset disposals in Slovenia and Hungary. These negative trends were counteracted~~ by continuing efficiencies and plant optimization, which drove a reduction in the refining breakeven margin down to $4.2 per barrel. The Chemical business’ results were affected by an unfavorable trading environment, which hit commodity margins.other unplanned shutdowns.

Year ended December 31,
2014 2015 2016
Refining & Marketing and Chemicals (€ million)
GAAP operating profit (loss) (2,811) (1,567) 723
(Profit) loss on inventory 1,746 877 (406)
Environmental provisions 138 137 104
Impairment losses 380 1,150 104
Net gains on disposal of assets 43 (8) (8)
Risk provisions (5) 28
Provision for redundancy incentives (4) 8 12
Fair value gains/losses on commodity derivatives 41 68 (3)
Reclassification of currency derivatives and translation effects to management measure of business performance 18 5 3
Other 37 30 26
Total gains and charges 2,399 2,262 (140)
Non-GAAP operating profit (loss) (412) 695 583

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	Year ended December 31,
	2019		2018		2017
Refining & Marketing and Chemicals	(€ million)
GAAP operating profit (loss)		(854)		(380)		981
(Profit) loss on inventory		(318)		234		(213)
Environmental provisions and other costs		244		243		136
Impairment losses (impairment reversals), net		922		193		54
Net gains on disposal of assets		(5)		(9)		(13)
Provision for redundancy incentives		8		8		(6)
Other		(45)		91		52
Total gains and charges		806		760		10
Non-GAAP operating profit (loss)		(48)		380		991
– Refining & Marketing		220		390		531
– Chemicals		(268)		(10)		460

Corporate and Other activities. These activities are mainly cost centers comprising holdings, financing and treasury ~~headquarters,~~activities in support of operating subsidiaries, central functions like information technology,

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legal counselling, human resources, ~~self-insurance~~insurance activities general and administrative support, as well as the Group environmental clean-up and remediation activities performed by the subsidiary ~~Syndial.~~EniRewind and the Energy Solutions business engaged in the development of renewable energy.

The aggregate Corporate and Other activities reported an operating loss of ~~€681~~€710 million in ~~2016 representing~~2019, an increase of ~~€184~~€19 million from ~~2015,~~2018, or ~~37%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures.~~

The aggregate Corporate and Other activities reported an operating loss of €497 million in 2015 representing a decrease of €21 million from 2014, or 4.1%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures.2.7%.

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

~~Net finance expense~~

Year ended December 31,
2014 2015 2016
(€ million)
Gain (loss) on derivative financial instruments 165 160 (482)
- Options 68 33 24
- Derivatives on exchange rate 51 96 (494)
- Derivatives on interest rate 46 31 (12)
Exchange differences, net (415) (354) 676
Net income from financial activities held for trading 24 3 (21)
Interest income 19 19 15
Finance expense from banks on short and long-term debt (871) (838) (757)
Finance expense due to the passage of time (293) (291) (312)
Other finance income and expense, net 41 (171) (110)
(1,330) (1,472) (991)
Finance expense capitalized 163 166 106
(1,167) (1,306) (885)

~~2016 compared to 2015~~. In ~~2016,~~2019, net finance expenses were ~~€885~~€879 million, ~~down by €421~~a small improvement of €92 million ~~compared~~from 2018. This reduction was due to ~~2015 reflecting the recording of~~lower losses at fair-valued currency ~~gains partly offset by negative fair value adjustments on currency~~ derivatives, ~~(for a net positive effect of €440 million), with the latter~~ lacking the formal criteria to be designated as hedges under IFRS. Furthermore, lower finance expense on debt were recorded due to the reduction in net borrowings and to lower interest rates reflecting accommodative monetary policies adopted by the Central Banks worldwide. These positives wereIFRS, partly offset by ~~impairment losses~~lower gains on ~~certain financing~~currency translation differences at dollar-denominated payables and receivables ~~granted~~accrued by Italian subsidiaries, as the Group normally pools different exposures to ~~equity-accounted entities which are currently executing industrial projects on Eni’s behalf (€121 million). Furthermore, a discount expense of €129 million was recognized relating~~the currency risk retained by operating subsidiaries and then hedges the Group net exposure to ~~certain receivable in~~ the E&P segment owed by certain NOCs due to agreements to repay the overdue amount in instalments with the proceeds associated with mineral initiatives. On that basis, the discount rate utilized reflected also the mineral risk.

~~2015 compared to 2014. In 2015,~~2019 net finance expenses include €378 million relating to the recognition of finance expenses for lease liabilities, as required by IFRS 16. Furthermore, finance expense from banks on short and long-term debt increased by €55 million reflecting the increase in net borrowings.

Other net finance income and expense were ~~€1,306~~a gain of €17 million, upreverting a loss of €173 million accounted in 2018 driven by €139 million compared to 2014. The higher gains on derivatives on exchange rate (up €45 million) which did not meet the formal criteria to be designated as hedges under IFRS were more than offset by the negative effect of the impairment of operating financing receivables ~~and securities for financing operating activities related to a Nigerian project following the revision of the commodity price scenario. The balance of net expenses was helped~~due by ~~a reduction~~an equity-accounted entity, which engaged in the ~~liability relating~~execution of an exploration projects that was written-off due to the fair-valued options (€33 million) embedded in the convertible bond relating to Snam shares. The reduction reflected the exercise of the option to convert the bond in Snam shares for approximately 6% of the share capital of the investee, with the remaining portion of the bond corresponding to approximately 2% of the share capital closer to maturity.an unsuccessful outcome.

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f) Net income from investments

~~2016 compared to 2015~~. In ~~2016~~2019 the Group reported a net ~~loss~~profit from investments of ~~€380~~€193 million ~~and mainly~~ related to:

~~(i)~~i).

~~results~~dividends of ~~equity-accounted entities (an overall net loss of €326 million), mainly reported~~€247 million paid by ~~the Exploration & Production segment due to a weaker commodity scenario and the economic difficulties recorded~~minority investments in certain Countries with a negative impact on the level of inflation and exchange rates. Particularly, the segment incurred a loss of €144 million mainly related to our joint ventures in Venezuela (PetroSucre,entities which ~~book~~were designated at fair value ~~was completely written off, Cardón IV and PetroBicentenario) driven by changed economics due to the local currency devaluation and rising inflation leading to escalating operating costs.~~

~~(ii)~~

~~a loss of €144 million was recorded on the equity-accounted interest retained in Saipem. This was driven by the recognition of asset impairment charges and~~through other extraordinary expenses accounted for in Saipem’s results due to the impairment review performed by the investee at its CGUs based on its updated industrial plan. That plan, announced in October 2016, factored in a slower recovery in the oil market and in investment plans of the international oil companies;

~~(iii)~~

net losses on the divestment of interests (€14 million) mainly relating to the disposal of the residual 2.22% interest in Snam (€32 million), offset by gains on the divestment of interests (€18 million) mainly of the 100% share in Slovenija doo, Eni Hungaria Zrt and other non-core interests;

~~(iv)~~

other losses mainly relating to an impairment charge recorded in G&P related to the interest in Unión Fenosa Gas SA (€84 million) due to a reduced profitability outlook and the impairment of receivables in the E&P segment owed by the equity-accounted PetroSucre SAcomprehensive income under IFRS 9 except for dividends ~~resolved but yet to be paid (€65 million).~~

which are recorded through profit. These ~~losses were partly offset by dividends received from~~ entities ~~accounted for at cost (€143 million) relating to~~mainly comprised Nigeria LNG Ltd (€~~76 million)~~186 million, where Eni has an interest of 10.4%) and Saudi European Petrochemical Co (€~~45 million).~~46 million, where Eni has an interest of 10%);

~~2015 compared to 2014~~

ii). ~~Net income from~~

a loss of €88 million recorded at equity-accounted investments, mainly in ~~2015 was a net gain of €105 million~~the R&M and ~~mainly related to: (i) dividends received from entities accounted for at cost~~Chemical segment (€~~402 million), relating to Nigeria LNG Ltd (€222~~63 million) and Snam SpA (€72 million); (ii) gains on disposal of investments (€164 million) which related to a gain recorded on the sale of an 8% interest in Galp (€98 million), gains on the divestment of a 6.03% interest in Snam (€46 million), gains on the divestment of refining infrastructures in Eastern Europe (€70 million), as well as the loss (€47 million) related to the divestment of minor assets in the ~~Gas & Power business in Argentina;~~Corporate and ~~(iii)~~ other ~~net gains including~~activities (€21 million). These share of profits at equity-accounted investments included the ~~alignment to stock price at December 31, 2015~~contribution of the Snam stock prices pertaining to Eni after the exercise of the conversion right by the bondholders (€49 million calculated on the 2.22% interest owned by Eni at the closing date). Those gains were partly offset by impairment losses registered in the business: (i) E&P relating to Angola LNG Ltd amounting to €469 million, including production and operating costs related to the start-up of liquefaction plant due to the revision of commodity scenario; and (ii) Gas & Power related to the interest on Unión Fenosa Gas SAupstream joint venture Vår Energi (€49 million).

~~These gains are further explained in “Item 18 – note 20 – Investments – of the Notes on Consolidated Financial Statements”.~~

~~g) Taxes~~

~~2016 compared to 2015~~. In 2016, income taxes amounted to €1,936 million, down by €1,186 million compared to 2015, or 38%. These lower charges mainly reflected lower write-downs of deferred tax assets in connection with improved projections of future taxable profit against which those assets would be utilized compared to 2015. Particularly, in 2015 deferred taxes were written down by €1,740 million relating to foreign subsidiaries of the E&P segment and Italian subsidiaries due to a deteriorated profitability outlook. By contrast, the write-downs of deferred tax assets in 2016 were offset by write-ups. In addition, considering the expected outcome of ongoing negotiations to settle disputed receivables owed by the Nigerian national oil company, the Company utilized a provision for deferred tax liabilities for €380 million as those receivables were considered tax-deductible.

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

g) Taxes

In 2015 and in 2016, the Group reported tax rate was much higher than the Group historical tax rates. This negative trend was negatively affected by the increased share of taxable profit earned in PSA contracts which bear higher-than-average rates of tax. Furthermore, in many jurisdictions where the Group reported pre-tax losses, the Company was not in the position of recognizing deferred tax assets, due to lack of sufficient future taxable profit against which those tax assets would be utilized. Management is estimating that in the four-year plan 2017-2020 the Group tax rate will progressively normalize in line with an expected recovery in the E&P results in concession contracts and an expected recovery in the pre-tax profit of Italian subsidiaries due to the ongoing upgrading plans at our G&P, R&M and Chemical businesses.

~~2015 compared to 2014. In 2015,~~2019, income taxes amounted to ~~€3,122~~€5,591 million, down by ~~€3,344~~€379 million compared to ~~2014,~~2018, or ~~51.7%, mainly reflecting~~6.3%. This decrease reflected lower income before taxes ~~currently payable~~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 ~~subsidiaries in~~ the Exploration & Production segment ~~operating outside Italy due~~in jurisdictions subject to higher-than-average tax rates, the tax effect related to a ~~declining~~loss incurred in connection with the reselling of gas entitlements of a Libyan partner as disclosed in the “executive summary” section, while taxable ~~profit. In spite of the fact that~~losses were incurred in ~~2015 Eni’s group pre-tax earnings were~~jurisdictions with a ~~loss, the Group incurred a net~~lower-than-average statutory tax expense. This negative development was influenced by a higher tax rate in E&P. The main drivers of this were three. First, the segment’s taxable profit was mainly earned in PSA contracts, which, although more resilient in a low-price environment due to the cost recovery mechanism, nonetheless bear higher-than-average rates of tax. Secondly, there was higher incidence of certain non-deductible expenses on the pre-tax profit lowered by the scenario. In addition, the tax rate was impacted by lower recognition of deferred tax assets relating operating losses due to a reduced profitability outlook (€1,058 million).rate. The Group tax rate was also negatively impacted by the write-off of ~~Italian~~ deferred tax assets ~~and other changes~~ of ~~€1,607~~approximately €900 million ~~in the full year~~ due to projections of lower future taxable profit at Italian ~~subsidiaries and the reduction of the statutory~~subsidiaries.

In 2020, we expect that a lower crude oil price environment will negatively affect our tax ~~rate from 27.5% to 24%, which was considered as substantially enacted at the reporting date.~~rate.

Liquidity and capital resources

Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and ~~acquisitions~~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 ~~assets.~~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,
2014 2015 2016
(€ million)
Net profit - continuing operations 1,808 (7,399) (1,044)
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 10,898 17,216 7,773
- net gains on disposal of assets (224) (577) (48)
- dividends, interest, taxes and other changes 6,600 3,215 2,229
Changes in working capital related to operations 2,199 4,781 2,112
Dividends received, taxes paid, interest (paid) received during the period (6,812) (4,361) (3,349)
Net cash provided by operating activities - continuing operations 14,469 12,875 7,673
Net cash provided by operating activities - discontinued operations 273 (1,226)
Net cash provided by operating activities 14,742 11,649 7,673
Capital expenditures - continuing operations (11,178) (10,741) (9,180)
Capital expenditures - discontinued operations (694) (561)
Capital expenditures (11,872) (11,302) (9,180)
Investments and purchases of consolidated subsidiaries and businesses (408) (228) (1,164)
Disposals of consolidated subsidiaries, businesses, tangible and intagible assets
and investments 3,684 2,258 1,054
Other cash flow related to investing activity (*) (**) 21 (1,651) 5,736
Changes in short and long-term finance debt (628) 2,126 (766)
Dividends paid and changes in non-controlling interests and reserves (4,434) (3,477) (2,885)
Effect of changes in consolidation, exchange differences and cash and cash equivalents related to discontinued operations 78 (780) (3)
Change in cash and cash equivalents for the year 1,183 (1,405) 465
Cash and cash equivalents at the beginning of the year 5,431 6,614 5,209
Cash and cash equivalents at year end 6,614 5,209 5,674

~~(*)~~

~~For 2016, the item also includes the reimbursement of intercompany financing loans owed to Eni by Saipem for € 5,818 million.~~

~~(**)~~

Net cash used in investing activities included investments in and divestments of certain financial assets (mainly bank deposits) to absorb temporary surpluses of cash or as part of our ordinary management of financing activities. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. Furthermore, due to the Company’s decision to retain a cash reserve by investing the proceeds of the disposal plan in the purchase of held-for-trading securities, net cash used in investing activities also includes investments and divestments of those securities. Also these held-for-trading financial assets are netted against finance debt in determining the Group net borrowings. For more information on their composition see Note No. 9 to the Consolidated Financial Statements. For the definition of net borrowings, see “Financial Condition” below. Cash flows of such investments were as follows:

(€ million) 2014 2015 2016
Investing activity:
- securities (19) (140) (1,317)
- financing receivables (519) (343) (272)
(538) (483) (1,589)
Disposal:
- securities 32 1
- financing receivables 92 182 6,860
124 183 6,860
Net cash flows used in investing activity (414) (300) 5,271

	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

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~~The table below sets forth the principal components of Eni’s change in net borrowings~~ ~~(1)~~ ~~for the periods indicated.~~

Year ended December 31,
2014 2015 2016
(€ million)
Net cash provided by operating activities 14,742 11,649 7,673
Capital expenditures (11,872) (11,302) (9,180)
Acquisitions of investments and businesses (408) (228) (1,164)
Disposals 3,684 2,258 1,054
Other cash flow related to capital expenditures, investments and divestments 435 (1,351) 465
Net borrowings(1) of acquired companies
(19)
Net borrowings(1) of divested companies
83 5,848
Exchange differences on net borrowings and other changes (850) (818) 284
Dividends paid and changes in minority interest and reserves (4,434) (3,477) (2,885)
Change in net borrowings(1)
1,278 (3,186) 2,095
Net borrowings(1) at the beginning of the year
14,963 13,685 16,871
Net borrowings(1) at year end
13,685 16,871 14,776

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

(*)

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

(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 ~~certain components~~the line items of ~~Eni’s change in net borrowings~~the profit and loss account

In ~~2016,~~2019, adjustments to reconcile net profit ~~from continuing operations~~ to net cash provided by operating activities ~~from continuing operations~~ mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization and impairment charges ~~and reversals~~ and the write-off of tangible and intangible assets (€~~7,434~~10,594 million). Adjustments to net profit also included accrued income taxes (€~~1,936~~5,591 million) and interest expense (€~~645~~1,027 million), which were ~~more than~~partly offset by amounts actually paid (€~~2,941~~5,068 million and ~~€780~~€1,029 million, respectively).

~~In 2015, adjustments to reconcile net~~

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Net profit ~~from continuing operations to net cash provided~~was negatively impacted by ~~operating activities from continuing operations mainly~~extraordinary credit losses related to ~~non-monetary charges~~a valuation allowance for doubtful accounts incurred in the E&P business and ~~gains, which primarily regarded depreciation, depletion, amortization, impairment charges (impairment reversals, net) and write-off~~certain provisions for an overall amount of tangible and intangible assets (€16,162 million). Adjustments to net profit also included gains on disposals (€577 million) relating mainly to the sale of a number of oil&gas properties in Nigeria, accrued income taxes (€3,122 million) and interest expense (€659 million) more than offset by amounts actually paid (€4,295 million and €692 million, respectively). Cash-outs for income taxes were partly offset by the reimbursement and the disposal to financing institutions of certain tax receivables due to the parent company (approximately €900 million).€336 million.

a) Changes in working capital related to operations

In ~~2016,~~2019, working capital generated an inflow of ~~€2,112~~€366 million. This was mainly due to a positive balance between trade receivables collected and trade payables paid (a net inflow of ~~€2,781~~€83 million) which reflected the higher volume of trade receivables due subsequently to the reporting date which were sold to financing institutions compared to the previous reporting period (about €1 billion). This inflow was partly offset by utilizations of the risk provision for €1,043 million, part of which related to the settlement of obligations towards third parties mainly in the G&P segment also in relation to the final award of an arbitration procedure involving a long-term gas buyer. Conversely an advance made to the same buyer in the previous reporting period was utilized. Finally the working capital inflow was partly absorbed by a reimbursement in-kind of a financing receivable due by an equity-accounted entity operating a gas field in Venezuela with trading receivables (€300 million) due by the Venezuelan state-owned oil company (PDVSA). Finally a positive adjustment related the item other current assets and liabilities (up by €647 million) which mainly reflected the impairment of receivables owed by National Oil Companies due to the expected outcome of ongoing negotiations to settle disputed amounts. The G&P segment was the main driver of the cash inflow from working capital in 2016, reflecting also non-recurring trends. We expect that the G&P working capital contribution will normalize going forward.

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In 2015, changes in working capital were positive for €4,781 million as a result of: (i) a positive balance between trade receivables collected and trade payables paid (a net inflow of €2,602 million), which was mainly driven by a positive performance in the Gas & Power segment; (ii) decreasing inventories (a positive €1,638 million) as a result of the alignment of the book value of crude oil and products to market prices (this item being an adjustment of the inventory loss recorded in net profit and as such is not a cash item), as well as reduced inventory levels in R&M due to optimizations measures; and (iii) a positive inflow related to other current assets and liabilities (up by €498 million) which mainly reflected a net positive inflow in the Gas & Power segment ~~due~~and because we collected advances on future supplies of equity gas to state-owned partners in Egypt in implementation of the agreements designed to provide adequate funding to the ~~collection of pre-paid volumes of gas under take-or-pay contracts and~~ongoing capital projects to develop hydrocarbons reserves in the ~~collection of receivables from supplied long-term customers.~~Country (€280 million), mainly the Zohr project. These inflows were partly offset by ~~a greater exposure~~the outflows in connection with the settlement of an arbitration proceeding which was provisioned in the ~~E&P segment towards joint venture partners.~~previous reporting period.

~~b) Investing activities~~

	Year ended December 31,						Year ended December 31,
	2014		2015		2016		2019		2018		2017
	(€ million)						(€ million)
Exploration & Production		10,156		9,980		8,254		6,996		7,901		7,739
Gas & Power		172		154		120		230		215		142
Refining & Marketing and Chemicals		819		628		664		933		877		729
Corporate and other activities		113		64		55		231		143		87
Impact of unrealized intragroup profit elimination		(82)		(85)		87		(14)		(17)		(16)
Capital expenditures - continuing operations		11,178		10,741		9,180
Capital expenditures - discontinued operations		694		561
Capital expenditures		11,872		11,302		9,180		8,376		9,119		8,681
Acquisitions of investments and businesses		408		228		1,164		3,008		244		510
		12,280		11,530		10,344		11,384		9,363		9,191
Disposals		(3,684)		(2,258)		(1,054)

Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments								(504)		(1,242)		(5,455)

Capital expenditures totaled ~~€9,180~~€8,376 million and ~~€11,302~~€9,119 million, respectively in ~~2016~~2019 and in ~~2015.~~2018.

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 ~~€1,164~~€3,008 million in ~~2016~~2019 and ~~€228 million~~mainly related to the acquisition of a 20% interest in ~~2015. In 2016, they~~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 of the portfolio and at rebalancing along the hydrocarbons value chain. Other investments comprised ~~the subscription of the~~a share capital increase of ~~Saipem (€1,069 million)~~€39 million at the Lotte Versalis Elastomers Co Ltd joint venture engaged in the elastomers production in South Korea and minor ~~contribution to equity-accounted entities.~~assets.

In ~~2016,~~2019, disposals amounted to ~~€1,054~~€504 million and mainly related ~~to: (i)~~to the divestment of ~~the 12.503%~~a 20% interest in ~~Saipem SpA~~the Merakes discoveries to ~~CDP Equity SpA in January 2016 (€463 million), an interest in Snam due to exercise~~Neptune for €207 million, the sale of the ~~conversion right by bondholders~~wholly-owned subsidiary Agip Oil Ecuador BV (€~~332~~189 million) ~~as well as fuel distribution activities in Eastern Europe.~~and other minor non-strategic assets.

In 2015, disposals amounted to €2,258 million and mainly related to: (i) the divestment of an available-for-sale interest in Snam due to exercise of the conversion right by bondholders (€911 million); (ii) an available-for-sale interest in Galp Energia (€658 million) in order to reimburse an out-of-the-money convertible bond which was due in 2015; and (iii) the divestment of non-strategic assets in the Exploration & Production and in the R&M businesses.

In 2016, other cash flow related to investing activities were positive for €465 million and included the reimbursement in-kind of a financing receivable owed by our equity-accounted entity Cardon IV for €300 million. Cardon IV reimbursed Eni with a trade receivable due by the Venezuelan State-owned oil company (PDVSA) on the supplies of gas volume produced at the Perla project. Furthermore, the production restart of the Kashagan field and the achievement of a production milestone in the fourth quarter of 2016 triggered the reimbursement of the first instalment of a receivable of the divestment of an interest of 1.71% of the project to the Kazakh national oil company occurred in 2008, with a cash-in of €152 million.

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

In ~~2016,~~2019, dividends paid and changes in non-controlling interests and reserves (€~~2,885~~3,424 million) related ~~almost exclusively~~ to ~~cash dividends~~dividend paid to Eni shareholders (€~~2,881~~3,018 million, of which ~~€1,441~~€1,542 million relating to the ~~2016~~2019 interim dividend and ~~€1,440~~€1,476 million to the final dividend for fiscal year ~~2015.~~

~~In 2015, dividends paid~~2018) and ~~changes in non-controlling interests and reserves (€3,477 million) mainly related to: (i) cash dividends to~~the execution of a repurchase program of the Eni ~~shareholders (€3,457 million, of which €1,440 million relating to 2015 interim dividend and €2,017 million to the balance dividend~~share for ~~fiscal year 2014); and (ii) the distribution of dividends to non-controlling interests by other consolidated subsidiaries (€21 million).~~€400 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, ~~non-operating financing receivables~~a liquidity reserve made of held-for-trading securities and ~~securities~~finally other liquid assets not related to ~~operations.~~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 ~~€6,404~~€6,760 million as of end

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of ~~2016~~2019 and were accounted as mark-to-market financial instruments. Of this amount, securities issued by industrial companies and financial institutions were €5.3 billion. For further information, see “Item 18 – ~~note 9~~Note 6 – Financial assets held for trading – of the Notes on Consolidated Financial Statements”. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced compared to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus 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.

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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,
2015 2016
Short-term Long-term Total Short-term Long-term Total
(€ million)
Finance debt (short-term and long-term debt)
8,396 19,397 27,793 6,675 20,564 27,239
Cash and cash equivalents (5,209)
(5,209)
(5,674)
(5,674)

Securities held for trading and other securities held for non operating purposes (5,028)
(5,028)
(6,404)
(6,404)

Non operating financing receivables (685)
(685)
(385)
(385)

Net borrowings (2,526) 19,397 16,871 (5,788) 20,564 14,776

As of December 31,
2015 2016
Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS (€ million) 57,409 53,086
Ratio of finance debt to total shareholders’ equity including non-controlling interest 0.48 0.51
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest (0.19) (0.23)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) 0.29 0.28

	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

In 2016, net borrowings amounted to €14,776 million, representing a €2,095 million decrease from 2015. This reduction was driven by repayment of debt due to the net cash flows provided by operating activities of continuing operations (€7,673 million) and the closing of the Saipem transaction, which entailed net proceeds of €5.2 billion. These latter comprised the reimbursement of financing receivables due to Eni by the former subsidiary (€5,818 million), the proceeds of the disposal of a 12.503% interest in the entity (€463 million), net of the cash-out to subscribe pro-quota Saipem’share capital increase (€1,069 million). Other divestment for the year amounted to €0.6 billion and mainly related to an interest in Snam due to exercise of the conversion right by bondholders (€332 million) as well as fuel distribution activities in Eastern Europe.

These inflows funded cash outflows relating to capital expenditures totaling €9,180 million and dividend payment to Eni shareholders amounting to €2,881 million, with the surplus used to pay down finance debt.

Furthermore, the change in the Group net borrowing y-o-y was influenced by the reclassification of financial assets held by the Group captive insurance company as non operating assets, which have been netted againstAt December 31, 2019, total finance debt ~~in determining the Group net borrowings (with a positive effect~~ of €0.6 billion). In previous reporting periods, those financial assets were committed to fund the loss provision and as such were part of capital employed. The change in classification reflects new regulatory requirements applicable to the exercise of the insurance activity from January 1, 2016, based on the provisions of EU Solvency II Directive (the so-called Minimum Capital Requirement – MCR – and Solvency Capital Requirement – SCR). The new rules require that insurance companies meet certain capital and solvency ratios as minimum requirements to continue performing the insurance activity. Therefore, it is no longer necessary to commit the financial assets of the insurance company to funding the loss provisions. Accordingly, those assets, which mainly comprise available-for-sale securities and bank deposits, have ceased to be classified as held for operating purposes.

~~The ratio of finance debt to total equity was 0.51 at 2016 year-end.~~

The Group Non-GAAP measure of its financial condition “Leverage” was 0.28 at December 31, 2016 reporting a decrease from 0.29 as of the end of 2015. This decline was driven by lower net borrowing, the effects of which were partly offset by a reduction in the Group total equity as explained below.

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Total equity decreased by €4,323 million from December 31, 2015. This was due to the net loss (€1,457 million), the derecognition of Saipem non-controlling interest (€1,872 million), as well as dividend distribution of €2,885 million (including the 2015 balance and the 2016 interim dividends paid to Eni’s shareholders amounting to €2,881 million). These effects were partially offset by a positive change in the cash flow hedge reserve (€883 million) and positive foreign currency translation differences (€1,198 million) due to the 3.2% depreciation of the euro against the US dollar at year end (down by 3.2% due to the exchange rate recorded on December 31, 2016 at 1.054 euro, compared to 1 euro = 1.089 US$ at December 31, 2015).

~~Total debt of €27,239~~€24,518 million consisted of ~~€6,675~~€5,608 million of short-term debt (including the portion of long-term debt due within twelve months equal to ~~€3,279~~€3,156 million) and ~~€20,564~~€18,910 million of long-term debt. At the same date, lease liabilities were €5,648 million (short-term portion €889 million).

Total finance debt included unsecured bonds for ~~€19,003~~€18,779 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to ~~€3,724~~€2,611 million (including accrued interest and discount). Bonds issued in ~~2016~~2019 amounted to ~~€2,984~~€1,635 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro ~~(90%~~(69%), U.S. dollar ~~(7%), British pound (2%~~(30%) and 1% in other currencies.

In 2019, net borrowings amounted to €17,125 million, representing a €8,836 million increase from 2018. This increase was driven by the initial recognition of the lease liabilities upon the adoption of IFRS16, which amounted to €5,759 million. The effect of the adoption of IFRS 16 on the Group net borrowings included €1,976 million of lease liabilities pertaining to joint operators in Eni-led upstream unincorporated joint ventures, which will be recovered through a partner-billing process. Excluding the overall impact of the adoption of IFRS 16, net borrowings would have been at €11,477 million, increasing

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by €3,188 million compared to December 31, 2018. This increase was mainly driven by the acquisition of a 20% interest in ADNOC Refining for a cash consideration of €2.9 billion, as cash flow from operating activities of €12.39 billion was able to fund the capital expenditure incurred in connection with the program of exploring for and developing hydrocarbons reserves and other capital projects (€8.4 billion), as well as to fund a cash return to shareholders of €3.4 billion consisting of 3 billion of cash dividends and €0.4 billion of stock repurchases.

The ratio of finance debt to total equity was 0.63 at 2019 year-end, including the impact of IFRS 16.

Total equity decreased by €3,173 million from December 31, 2018. This was due to the profit for the year (€155 million) and positive foreign currency translation differences (€604 million; the exchange rate of the euro against the US dollar recorded on 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 of Eni’s shareholders (€3,018 million), a negative change in the fair value of the cash flow hedge reserve (-€679 million) as well as the impact of the share buyback (-€400 million) detracted from net equity.

The Group Non-GAAP measure of its financial condition “Leverage” 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 the impact of IFRS 16 altogether, leverage would be 0.24.

Capital expenditures by segment

Exploration & ~~Production~~Production.. In ~~2016,~~2019, capital expenditures of the Exploration & Production segment amounted to ~~€8,254~~€6,996 million, mainly related to the development of oil&gas reserves (€~~7,770~~5,931 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, ~~Angola,~~Nigeria, Kazakhstan, Indonesia, ~~Iraq, Ghana~~Mexico, the United States and Norway. Development expenditures in Italy also comprised the upgrading of certain plants at the Viggiano oil center in Val d’Agri, which did not alter the plant set up. This upgrading addressed certain objections made by jurisdictional Authorities about the proper function of the plants and were duly authorized by the competent department of the Italian Ministry of Economic Development. Due to this upgrading, plant activities were regularly restarted following notification by the public prosecutor that it has definitively repealed the plant seizure. (see – Item 4 – Exploration & production segment – Italy) as well as sidetrack and workover activities in mature fields.Angola. Exploration expenditures (€~~417~~586 million) were directed in particular into Egypt, ~~Indonesia, Libya~~Angola, Mexico, the United Arab Emirates and ~~Angola.~~Libya.

In ~~2015, capital expenditures~~2019, a total amount of ~~the Exploration & Production segment amounted to €9,980~~€400 million ~~mainly~~ related to the ~~development~~purchase of ~~oil&gas~~proved and unproved reserves ~~(€9,341 million). Significant expenditures were directed mainly outside Italy,~~ in ~~particular Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia~~Alaska and the United States. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri, as well as sidetrack and infilling activities in mature fields. Exploration expenditures amounting to €566 million were directed outside Italy, in particular in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia.Algeria.

Gas & ~~Power~~Power.. In ~~2016,~~2019, capital expenditures in the Gas & Power segment totaled ~~€120~~€230 million and mainly related to gas marketing initiatives (€176 million) due to ~~improve flexibility~~the capitalization of expenses for the ~~combined-cycle power plants (€41 million)~~acquisition of retail customers, and to ~~develop~~ the ~~gas marketing activity~~business of power generation (€~~69 million).~~

In 2015, capital expenditures in the Gas & Power segment totaled €154 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (€69 million) and to develop the gas marketing activity (€6942 million).

Refining & Marketing and Chemicals. In ~~2016,~~2019, capital expenditures in the Refining & Marketing and Chemicals segment amounted to ~~€664~~€933 million and regarded mainly: (i) refining ~~activities~~activity in Italy and outside Italy (€~~298~~683 million) ~~aiming fundamentally~~for the rebuilding of the EST conversion plant at ~~plants improving,~~the Sannazzaro refinery, the upgrading of the Gela refinery into a biorefinery, increasing plants’ integrity, as well as initiatives ~~in the field of health, security~~to comply with stricter environmental and ~~environment;~~safety standards; (ii) marketing activity, mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the Rest of Europe (€~~123~~132 million); (iii) plant upgrading, efficiency and ~~maintenance at petrochemical plants~~compliance to stricter environmental and safety standards in the Chemical business (€~~200~~93 million).

In 2015, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €628 million and regarded mainly: (i) refining activities in Italy and outside Italy (€282 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; (ii) upgrading and rebranding of the refined product retail network in Italy (€75 million) and in the Rest of Europe (€51 million); (iii) upgrading and maintenance at petrochemical plants (€177 million).

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Recent developments

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

	Three months ended December 31		Three months ended March 31,		January 1 through March 17,		Three months ended March 31,		Three months ended March 31,
	2016		2016		2017		2019		2020
Average price of Brent dated crude oil in U.S. dollars(1)		49.46		33.89		54.66		63		51
Average EUR/USD exchange rate(2)		1.078		1.102		1.063		1.136		1.100
Standard Eni Refining Margin (SERM)(3)		4.7		4.2		4.2		3.4		3.3

Gas at the PSV in $/mmBTU								7.1		3.7

(1)

Price per barrel. Source: Platt’s Oilgram.

(2)

Source: ECB.

(3)

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.

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In the period January 1 – March ~~17, 2017~~31, 2020 the Brent crude oil price was ~~54.66$/~~approximately 51 $/BBL on average, ~~61% higher~~approximately 20% lower than in the first quarter of ~~2016 and 10% higher than in the fourth quarter 2016.~~2019. This trend will ~~positively~~negatively affect reported revenues, profitability and cash flow of our Exploration & Production ~~segment.~~segment in 2020. See “management expectations of operations” below.

Significant transactions

~~On March 9, 2017, Eni and ExxonMobil signed sale and purchase agreement whereby ExxonMobil is going to acquire a 25% indirect interest~~The significant transactions that occurred post-closing are described in the Area 4 block, offshore Mozambique. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The agreed terms include a cash price of approximately $2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore. This operating model will enable the use of best practices and skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project.

The Company’s Annual General Shareholders Meeting scheduled on April 13, 2017, has been convened to approve the full year dividend proposal of €0.80 per share of which 0.4 paid as interim dividend in September 2016. Eni expects to pay the balance of the dividend for fiscal year 2016 amounting to €0.40 per share in April 2017. The total cash out is estimated at approximately €1.4 billion.item 4.

Management’s expectations of operations

THE COVID-19 IMPACT and CURRENT TRENDS IN THE OIL MARKET

The outbreak of a contagious disease known as COVID-19 which has spread rapidly 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 an agreement for additional oil production cuts proposed by some participants to counteract the COVID-19 effects. These developments together triggered a collapse in crude oil prices. As of the end of March 2020, the price of the Brent crude benchmark has fallen by more than 50% from the value recorded before the onset of the disease at more than 65 $/bbl in early January 2020; 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.

Should these developments prolong beyond the short term, they could represent a material risk to the outlook of oil&gas companies considering the already weak fundamentals of the sector due to continued oversupply and changing consumers’ attitudes toward hydrocarbons due to rising climate – related issues.

Management has estimated the Company’s operating cash flows to vary by approximately €150 million for each one-dollar change in the price of the Brent crude oil benchmark with respect to the price case assumed in Eni’s financial projections for 2020; regarding the price of natural gas at the PSV, it has been estimated a variation of +/-€235 million in the operating cash flow for a +/-1 $/mmBTU change in the price of the PSV compared to our financial assumptions.

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 OPEC+ agreement effectively ceases 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. However, in recent years the Company has taken several steps to improve its balance sheet and the resilience of the business to the volatility of hydrocarbons prices. Due to continued exploration success at competitive discovery costs, the deployment of an efficient model to develop hydrocarbons reserves based on a phased approach, reduction of time-to-market and design-to-cost, as well as continued control of operating expenses, we believe that our portfolio of oil&gas projects can withstand a significant oil price downturn, leveraging on low break-even prices. We retains 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 and are marked to market, which together with cash on hands of approximately €6 billion will cushion the impact of a price downturn, also of severe proportions. 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 commitment of 2020 include long-term debt maturities of approximately €3.2 billion, 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.

We are continuing to evaluate the effects of the recent trends in the oil market. This assessment includes an update to the oil price scenario and management actions to counteract the changed environment, the effects of which are currently not yet determinable and will be accounted for in future

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reporting periods. To date, in response to the sharp decrease in commodities prices and the foreseeable constraints arising from the COVID-19 pandemic, management has revised its capital plans and updated the commodities scenario for the years 2020 and 2021. Management is now assuming for planning purposes a Brent price of 40-45 $/bbl in 2020 and of 50-55 $/bbl for 2021. In 2020, management is planning to reduce capital expenditures by around €2 billion, equal to 25% of the amount originally planned, and opex by around €400 million. In 2021, Eni expects a capital expenditures reduction of around €2.5-3 billion, equal to 30-35% of the capex scheduled for the same year in the business Plan.

The projects involved in this capex reduction are related mainly to Upstream activities, particularly production optimization and new projects developments scheduled to start in the short term. In both cases, activities will be restarted as soon as appropriate market conditions return, and related production will be recovered accordingly. As a result of these measures and the current depressed scenario, production in 2020 is expected to be between 1.8 and 1.84 million barrels of oil equivalent per day, which would remain unchanged in the following year. Finally, management has resolved to suspend the share repurchase program. 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.

Exploration & Production

~~Management intends~~In the next four-year action plan 2020-2023, management will seek to boost the cash generation in the E&P segment leveraging on profitable production, ~~growth,~~ capital discipline, effective project execution and strict control of operating expenses and ~~project execution.~~ working capital.

Exploration ~~activities~~ will continue ~~to be key to~~driving the Company’s growth ~~prospects~~ in the short and long-term. ~~The Company is leveraging~~Our strategic guidelines for exploration in the next four years are to retain capital discipline by investing up to a maximum of 1 billion USD per year, to ensure cost-effective replacement of produced reserves and to support 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. This approach has paid off in recent years; for example in 2019 we made three near-field discoveries in Egypt and one in Nigeria which have been already put into production due to proximity to infrastructures. Furthermore, based on ~~its~~this approach, we have resumed exploration in our operated Block 15/06 off Angola, aiming at extending the life-cycle of our existing units of floating production (FPSO) in the area. We discovered several new fields in the area and one of these discoveries, Agogo, has been linked to our FPSO vessels as of lately;

•

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 ~~which envisages both~~in case of material discoveries.

Our dual exploration model contemplates the ~~rapid development~~acquisition of high interests in exploration leases and, in case of exploration success, the partial divestiture of the discovered resources ~~and the divestment~~with a view of ~~stakes of our exploration discoveries in order to accelerate~~accelerating the conversion of ~~our~~ resources into ~~cash. The effectiveness~~cash or of accomplishing asset swaps.

We are targeting a 3.5% average growth rate in hydrocarbons production up to a plateau of approximately 2.2 million boe/d in the 2020-2023 plan period. In 2020, we anticipate our ~~dual exploration model has been proven~~production to be negatively affected by the ~~divestment~~expected triggering of a ~~40% interest~~contractual revisions at our production sharing agreements in Libya.

Growth in the 2020-2023 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 ~~discovery~~field in Egypt, Block 15/06 in Angola and the Area 1 fields off ~~Egypt, with a value to Eni of approximately €2 billion including the reimbursement of the capital expenditure incurred in 2016 to develop the prospect,~~Mexico, as well as continuing production optimization to counteract fields natural decline. The main start-ups expected in the plan period include the projects that were sanctioned in 2019 or that are planned to be sanctioned shortly, mainly the cluster of oil discoveries in Area 1 offshore Mexico which was started in early production in 2019, the development of the new discoveries in Block 15/06 offshore Angola with the first one, Agogo, already started at the beginning of 2020, a number of projects operated by our JV Vår Energi in Norway (including Balder X and Johan Castberg) the ~~preliminary agreement signed for~~Merakes gas field in Indonesia, phase two of the ~~divestment~~Nenè Marine field in Congo, the gas discovery of ~~a 25% interest~~Coral in Area 4 offshore Mozambique, ~~with an expected cash consideration~~the Dalma gas fields offshore the UAE and other developments. We estimate that new field start-ups, production ramp-ups and expansion projects of ~~approximately $2.8 billion.~~

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We expect to increase our hydrocarbons production at an average rate of 3% across the 2017-2020 plan period. This growth target factors in the effects associated with our planned disposals. For 2017, we expect a production growth of approximately 5%. This grow will be fuelled organically by newexisting fields start-ups, full production at the Goliat and Kashagan projects and the ramp-up of the other fields started in 2016, the recovery of the full plateau at the Val d’Agri profit center and continuing production optimization to fight fields natural decline. The main start-ups of 2017 include the Zohr gas field off Egypt expected at year-end, the oil&gas project of Offshore Cape Three Points in Ghana, the East Hub of Block 15/06 off Angola and the Jangkrik gas project in Indonesia. The East Hub project has already achieved first oil in February 2017. In subsequent years, we are planning new project start-ups in Egypt, Angola, Algeria and Norway. New field start-ups, production ramp-ups and continuing production optimization will add approximately ~~850~~800 KBOE/d ~~in 2020.~~of new production by 2023. We ~~believe that~~have good visibility as to the ability to achieve those production targets ~~have good visibility~~ because they ~~related~~relate to already-sanctioned projects, mostly of which are ~~operated.~~operated, and to incremental development phases at our existing profit centers.

Our production plans ~~includes~~include assumptions relating to production levels in ~~Libya and Nigeria, which~~certain countries that are particularly exposed to risks of disruptions and political instability. In 2016, Libya represented approximately 20% of the Group total hydrocarbons productions for the year and going forward the contribution of Libya to our future production levels albeit slowing down will remain significant. To factor in possible risks of unfavorable geopolitical developments ~~mainly~~ in ~~Libya but also elsewhere in other~~those countries, ~~of Eni presence,~~ 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, ~~this~~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 are ~~incorporating our Brent price scenario of 55 $/BBL in 2017 and~~based on a gradual recovery in ~~the subsequent years~~Brent prices post 2020 up to our long-term case of 70 $/BBL in ~~2020~~2022 and going forwards (on constant monetary term ~~compared to 2020,~~2022, i.e. from ~~2020~~2023 onwards crude oil prices will grow in line with a projected inflationary rate). ~~See “Item 4 – Exploration & Production”.~~ Our ~~recovery~~pricing assumptions are based on forecast of a recovery in oil demand growth in the ~~progressive rebalancing~~medium term, against the backdrop of a moderate pace of expansion in the global ~~oil markets, which will be supported by the OPEC agreement reached in November 2016 to cut the cartel output joined~~economy. We also ~~by non-Opec members and the effects of the curtailment in expenditures made by~~expect that international oil companies ~~during~~will retain a disciplined approach to capital spending going forward, while US independent producers have shown recently the ~~downturn. However, there~~intention of shifting their focus from growth to shareholders’ returns. There are some risks to this outlook, including ~~effective compliance~~uncertainties over the strength of ~~OPEC member countries~~the global economy, which will be significantly and negatively affected in the short-term by the spread of a pandemic disease known as COVID-19, the ability of OPEC+ to control global prices in light 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 ~~planned production quotas~~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 ~~pace at which unconventional oil producers~~recent developments within the OPEC+, as discussed in the ~~US will be able to bring production back to markets, leveraging the short-cycle nature of this business and rising productivity.~~

Oil price assumptions are particularly significant when it comes to assessing the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. In 2016, the Company estimated that production entitlements in its portfolio of PSAs increased by approximately 20 KBOE/d, or 1,900 BBL/d for each $1 change in oil prices compared to 2015.previous paragraph. We ~~note that in case oil prices differ significantly from our own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.~~expect a weak trading environment throughout 2020.

Due to those risks and uncertainties, management intends to retain a strong focus on capital ~~discipline, project execution~~ and cost ~~control.~~discipline and on reducing the time-to-market of our reserves as levers to maintain our development projects profitable in a low price scenario. First, our capital ~~budget in~~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 E&P segment for the four-year plan 2017-2020 is estimated 13% lower than the previous capital plan 2016-2019 (in each cases net of the capex associated with planned disposals). In spite of an expected reduction in capital spending, our growth targets in 2017-2020 are above our previous planning assumptions relating the period 2016-2019 due to ourexecution risk leveraging on a phased approach in developing our ~~production~~ projects. ~~This approach will enable the Company to reduce financial exposure and to accelerate production start-ups.~~ Secondly, ~~we intended to be more selective on investment options. Thirdly,~~ we plan to ~~seek opportunities for further reductions in~~deliver our development and operating costs by renegotiating contracts for the supply of upstream plants, equipment and other infrastructures as well as the supply of oilfield services and drilling rates considering the uncertainties surrounding a recovery in expenditures by oil companies.

~~Finally, management will focus on delivering the~~ planned projects on time and on budget. ~~Some~~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. ~~Furthermore, in the past we experienced delays and cost overruns at certain projects, which were caused by~~

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~~poor execution by our EPC contractors.~~ We plan to mitigate those risks in the future by continuing deployment of our ~~capabilities~~skills and by ~~means of:~~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 ~~activities; (ii) increasing direct~~phases, for example we are exercising strict control ~~and governance on~~over construction, ~~activities; (iii) deploying our employees and competences to manage~~ hook-up and commissioning; and (iv) entering into framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants and increasing focus on supply chain programming to optimize order flows. Effective project execution(iii) the design-to-cost method whereby the Company has ~~been boosted in recent years by our changed approach in~~redirected its exploration ~~activities, which have been redirected~~efforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost ~~synergies. Furthermore, phased~~synergies; (iv) continuing progress in our technologies designed to improve drilling performance and the recovery factor; (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.~~years, thus reducing the risk of a volatile scenario.

~~Management also plans~~

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Finally, we plan to ~~increase~~seek opportunities for further reductions in our development and operating costs, for example by reducing the ~~share of operated production in the Company’s portfolio. We expect to operate more than 74% of the plan period production. Project operatorship enables the Company to better schedule~~downtime at our facilities and control project execution, expenditures and timely achievement of project milestones and to mitigate the operational risk associated with drilling activities at high pressure-high temperature wells and at deep waters well by deploying our technologies and competences. Eni estimates that these wells will represent approximately 13.5% of the planned wells to be drilled in 2017.

In the next four years, our exploration activities will focus on supporting the replacement of produced reserves and on contributing to cash generation. Our exploration investment will be mainly directed to:

~~Appraisal of the recent discoveries and near-field plays, where in case of success we can leverage on existing infrastructures in order to readily put into production the discovered resources;~~

~~ii)~~

~~Initiatives in new areas in proximity to end markets, targeting conventional prospects with high interests in order to implement our dual exploration model in case of material discoveries.~~

other measures.

Gas & Power

We ~~expect~~anticipate a weak outlook in the Gas & Power segment due to structural headwinds in the ~~industry as we~~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 ~~sluggish~~a weak demand ~~growth, oversupplies and strong competition across all of~~environment in our main reference markets, primarily in ~~Europe, including Italy.~~

~~We project a flat trend in gas demand in Europe~~Italy and in ~~Italy over~~other European countries, due to an ongoing economic downturn also driven by the ~~next four-year plan. Demand growth will be dampened by sluggish economic growth, rising~~impact of the COVID-19 and strong competition from renewables and trends for increasing energy efficiency. ~~On the supply side, the growing importance of liquid hubs and large availability of LNG will drive continuing competition and pricing pressure. Going forward~~Rising LNG supplies ~~will be fueled by the coming on stream of several export terminals in the United States which will monetize the country’s large reserves of shale~~have also increased markets liquidity and interconnections, reducing arbitrage opportunities. In our wholesale gas ~~and the start-up of important LNG projects in the Pacific area. These~~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 business is to ~~achieve structural~~gain stable profitability and ~~retain positive~~ cash ~~generation. Our strategy in the Gas & Power sector will leverage~~generation based on the ~~renegotiations of~~following drivers:

(i)

To continuously renegotiate our long-term gas supply contracts ~~in order~~ to align pricing ~~and volume~~ terms to current market conditions and dynamics ~~optimization~~as they evolve and to obtain operational flexibilities (volumes, points of ~~logistic costs, the development of~~delivery, etc)

(ii)

To effectively manage our portfolio of ~~highly profitable businesses~~assets (supply and ~~cost efficiencies~~sales contracts, their flexibilities and ~~operational streamlining.~~optionality and logistics availability) in order to extract value from market volatility;

~~Our take-or-pay, long-term supply contracts include revisions clauses whereby each counterpart has right to renegotiate~~

(iii)

To grow the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Leveraging on recent renegotiations, 90% of our portfolio of supply contracts is currently indexed to HUB prices and will benefit the 2017 performance. Looking forward, we expect to fully align our supply portfolio to market conditions and dynamics in terms of both pricing and volumes. Our renegotiation efforts will seek to obtain cost indexation that will track our pricing formulas, to align our procurement costs to prices prevailing in the wholesale market, which includes sales to large industrial and

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power companies and resellers, and to match our minimum contractual take with the dimension of our addressable market. The renegotiation strategy is subject to the constraints dictated by availability of the contractual windows. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will ultimately be achieved and the timing of recognition in profit. In case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration procedure could be commenced to solve the commercial dispute. Furthermore, Eni’s suppliers may file a counterclaim to dismiss Eni’s request for a price review or renewed contractual terms. These possible developments increase the risks and uncertainties relating the outcome of those renegotiations. Therefore, future results of the gasLNG marketing activities are subject to increasing volatility and unpredictability. The expected termination of certain long-term gas supply contracts with take-or-pay clause will reduce Eni’s contractual minimum take and will add flexibility to Eni’s portfolio and renegotiation strategy. Furthermore, we plan to almost complete the recovery of our pre-paid gas volumes due to the triggering of the take-or-pay clause in past reporting periods. This asset amounted to €0.3 billion at 2016 year-end. We expect to improve profitability in gas marketing through initiatives intended to reduce logistic costs by reselling unutilized transport capacity to other operators and by possibly benefitting from expected liberalization measures in the European gas system designated to increase the liquidity of spot markets.

The Company intends to grow its presence in market segments where margins can be sustained in the long-term. As part of this plan, we intend to strengthen our role as a global player in LNG trading where we plan to achieve steady profitability, also leveraging on integration with our upstream operations by marketing equity gas. We will seek to preserve margins on sales to large accounts bybusiness leveraging on the ~~Company’s multiple presence across various markets~~integration with the E&P segment with the aim of maximizing the profitability along the entire gas value-chain and ~~expertise~~of supporting the achievement of the final investment decisions at large gas upstream projects (for example in ~~delivering innovative and tailor-made offering structures~~Mozambique). Based on this approach in 2019 we made the final investment decision for the upgrading of the Bonny LNG project in Nigeria. We plan to ~~best suit customers’ needs by providing complex pricing formulas, hedging against~~accelerate the ~~commodity risk and flexibility in volumes collection. In the retail segment,~~growth of our ~~priority is~~contracted supplies of LNG to ~~maximize profitability and cash generation through more effective and efficient operations. We will closely monitor the level~~achieve a robust portfolio of ~~working capital~~reselling opportunities, and we ~~will be more selective in new customer additions in order to reduce~~are targeting 16 million tons of contracted volumes of LNG by 2025, of which 70% deriving from our equity production;

(iv)

To boost the ~~portfolio risk and counterparty losses. We intend to increase~~profitability of the ~~weight in our portfolio~~gas&power retail business, by enhancing the value of customers who are willing to sign supply contracts in the open market rather than opting to use the regulated tariffs established by Italian gas authorities. The Company’s marketing effort will address retail customers in Italy and in the main European markets in order to valorize 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 ~~brand identity,~~other than the ~~administrative advantages~~commodity and by continuing innovation in marketing processes including the deployment of digitalization in the ~~dual offer~~acquisition of ~~gas and electricity,~~new customers, a ~~competitive~~reduction in the cost to serve and ~~continuing innovation in processes, promotion and customer care and post-sale assistance. We believe that offering a wide range~~effective management of ~~valuable services with~~working capital. Our plans targets the ~~selling of the commodity will underpin the profitability~~expansion of our ~~retail operations considering that the regulatory modifications~~customer base to ~~the indexation~~11 million of ~~the raw material cost have substantially flatten the margin on the commodity. Management will also seek to improve profitability~~points of delivery by ~~means~~2023.

We make use of ~~cost efficiencies particularly by streamlining business support activities and reducing general and administrative costs.~~

~~Finally, the Company intends to capture margins improvements by means of trading activities by entering into derivative contracts both in the~~ commodity and ~~the~~ financial ~~trading venues in order~~derivatives to capture possible favorable trends in market prices, within the limits set by internal policies and guidelines that define the maximum tolerable level of market risk. As part of this strategy, the Company intends to improve results of operations by effectively managing the flexibilities associated with the Company’s assets (gas supply contracts, transportation rights, storage capacities, unutilized power capacity). This can be achieved through strategies of asset-backed trading by entering into derivative contracts to leverage on commodity price volatility,hedge us against the risks of ~~which might be absorbed~~different indexation formulas in ~~part~~our gas procurement costs vs. selling prices in relation to contracted sales or ~~entirely~~highly-probable sales. A number of these derivatives are not accounted as hedges in accordance to IFRS and consequently there 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 ~~natural hedge granted~~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 results were helped by this asset-backed trading leveraging the ~~asset availability. Asset-backed activities may lead~~high market volatility recorded in the year; however it is difficult to ~~gains, as well as losses the amount of which could be significant. For further information on the market risk and how the Company manages it see “Item 11 – Quantitative and Qualitative Disclosures~~make accurate forecast about ~~Market Risk”.~~future trends in this activity.

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

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contracts which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3.

These projections could be subject particularly to the risks of further contraction in demand or the total addressable market and the risks related to the outcome of contract renegotiations. For more information see the specific risk paragraph in “Item 3 – Risk factors”.

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Refining & Marketing

The outlook of the European refining sector is ~~unfavorable~~challenging due to structural headwinds in the industry pressured by overcapacity, ~~stagnant~~high global gasoline stocks, impact of energy efficiency on fuel ~~demand, energy efficiency~~consumptions and rising competition from cheaper products streams from the Middle East and other ~~areas.~~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 ~~in 2017 and going forward~~ to remain around the weak levels registered in 2016 at about 4$ per barrel, where the Company’s refining business is at breakeven. At the end of the plan period it is projected an improvement in refining margins due to the enactment ofon a ~~new regulation regarding the quality of fuel used~~downtrend in the ~~bunker segment.~~next four years and beyond, reflecting progressive reduction in the oil products crack spread. Furthermore, our refineries are exposed to price differentials shrinking between sour crudes vs. the Brent benchmark, which negatively affects the profitability of our complex refineries eroding 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 in a depressed downstream oil ~~environment, by further reducing~~environment. Our priority is to reduce the breakeven margin of Eni ~~refineries. The~~refineries in Europe, leveraging the full operability of our refining ~~business has undergone a restructuring process resulting in a reduction~~system, particularly with the restart of the ~~installed capacity by more than 30% versus~~EST high-conversion unit at the ~~2012 baseline. This process has comprised~~Sannazzaro refinery and the ~~conversion~~recovery of the Venice refinery into a green refinery for the production of bio-fuels based on a proprietary technology, the shutdown of Gela refinery, which is undergoing a transformation into a green refinery like the Venice site, asset disposals, the shutdown of unprofitable lines and other efficiency initiatives. We believe that additional optimization is needed considering the structural headwinds and volatility of the refining scenario. Our goal is to lower the breakeven margin to 3$ per barrel by 2018. The planned initiativesBayernoil plant. Other measures include ~~the completion of the Gela project and the second phase of Venice upgrading,~~ optimization of plant ~~setup~~run also in view of maximizing yields of valuable fuels and ~~continued~~improved 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 of improving the refinery efficiency and profitability. We are sponsoring a number of capital projects designated to upgrade the refinery capacity to process crudes with high sulfur content, 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 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 Gela plant was started in the second half of 2019, bringing installed capacity at our bio-refineries to 1 million tons per year, with profitable crack spreads between the cost of the bio feedstock and the bio-productions. We are planning to progressively phase out palm oil as a feedstock and replace it with more environmentally-sustainable feedstock; this process of substitution is expected to be completed by 2023.

Finally, we plan to pursue efficiency gains in logistics, to achieve energy ~~management~~savings and ~~capital discipline.~~ 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 ~~pressure to continue~~environment due to ~~weak demand trends,~~lack of entry barrier and of product differentiation, we are planning to ~~achieve a gradual improvement in results of operations~~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.

~~Retail operations abroad~~ Further value will be ~~focused on~~extracted by the ~~core markets of Germany, Austria, Switzerland and France, where we intend to exploit synergies with Italian operations, brand awareness, a fair market share and~~ development of ~~non-oil activities to retain steadily profitable operations. We have completed the refocusing program of~~ our ~~portfolio of activities exiting Eastern Europe.~~

~~Overall, we expect that under constant 2017 scenario assumptions,~~initiatives in the ~~next four-year plan~~segment of sustainable mobility and new fuels (for example the ~~business will generate enough cash to fund its capital expenditure plans~~recharging for electric vehicles, hydrogen and ~~to generate a surplus.~~compressed natural gas) and selling non-fuel products and services.

Chemical

The outlook in the chemical business is ~~unfavorable~~challenging due to ~~structural headwinds~~declining consumption of commodity plastics driven by an ongoing economic slowdown in Europe, lower growth in China and in other emerging economies and a downturn in the ~~industry pressured~~automotive sector which is one of the main end-markets of the chemicals business. The situation has been made worse by ~~overcapacity, weak macroeconomic growth~~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 ~~competition~~competitive pressures from cheaper products ~~streams~~stream in the main commoditized segments, like polyethylene, from ~~the~~producers in Middle East ~~Far East~~ and in the ~~US.~~US 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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our petrochemical commodities are exposed to the volatility of the crude oil-based feedstock costs. ~~Like the R&M business, our chemical activity has undergone a deep restructuring process.~~ Over the last few years, we have ~~lowered the cost base and exposure to commodity risk~~restructured our business by reducing capacity, divesting or exiting unprofitable lines, plant optimization and other efficiency measures as well as a shift in our product portfolio towards specialties, green chemicals and products with high technology content, which are less exposed to the scenario volatility. Looking forward we believe that further steps are needed to preserve profitable and cash-positive ~~operations, including self-financing the business capital requirements.~~operations. The industrial plan ~~contemplates~~identified the ~~completion~~following lines of action intended to improve resiliency to the ~~restructuring process at unprofitable sites, increased~~market volatility: (i) strengthening the productive footprint by means of improved plant ~~flexibility~~integration and ~~optimization, development of new products and specialties~~reliability as well as by rightsizing our captive ethylene capacity vs internal needs for the ~~start-up~~production of polyethylene; (ii) improving feedstock costs at our steam crackers by introducing a certain ~~joint ventures in East Asia~~degree of flexibility towards ethane; (iii) upgrading the product mix by developing differentiated products, leveraging on new applications through internal R&D; (iv) developing the international presence of our chemical business leveraging on proprietary technologies targeting markets with ~~local partners~~growth opportunities and access to ~~produce~~competitive feedstock and ~~market elastomers.~~outlets; and (v) developing our portfolio of green products and products from recycled plastics and renewable feedstock.

~~Overall, we expect that even under our conservative scenario assumptions the business will generate enough cash to cover its capital expenditures requirements along the plan period.~~

Liquidity and leverage

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~~Capital expenditure plans~~

Over the next four years, the Company plans to invest €31.6 billion, excluding capex associated with the disposal plan, to support continued organic growth in oil&gas production; approximately 86% of planned capital expenditures is expected to be directed to the Exploration & Production segment. Eni’s capital expenditure program is reflective of a lower oil price environment and of uncertainties aboutConsidering uncertain future trends in the oil ~~markets. Our capital expenditure plan will be more selective than~~markets and in the ~~past~~global economy, the risks of a macroeconomic downturn, oversupplies and ~~will focus on~~price volatility, which have been exacerbated by the ~~more profitable projects~~steep sell-off in portfolio and on project re-phasing and modularization. These optimizations and curtailments, as well as wider portfolio effects are expected to drive an 8% reduction in capital expenditure compared to the previous plan at constant exchange rates and net of capital expenditures associated with our disposal activity, without sacrificing our production growth targets. E&P capital expenditure for the four-year plan is expected to decrease by 13% compared to the previous plan. In 2017 we expect overall capexcommodity prices in the ~~range~~initial months of ~~€7.6 billion, down by 18% vs 2016 at a constant exchange rates and post portfolio transactions.~~

Development of oil&gas reserves will attract some €25 billion. Project start-ups and plateau enhancement at existing fields will be geographically diversified and executed mainly in Egypt, with the development of the very important Zohr gas discovery, Mozambique, Italy, Iraq, Kazakhstan, Nigeria, Norway, Libya, Angola and Ghana. Egypt will attract approximately 20% of the Group capital expenditure over the plan period.

Exploration capex will amount to €2.1 billion. Our projects will include appraisal of recent discoveries and near-field activities designed to provide fast production support and contribution to the cash flow, as well as new initiatives targeting conventional prospects with high working interest in order to support Eni’s dual exploration model in case of material discoveries.

We are planning to invest approximately €2.2 billion in R&M which will mainly be directed to the completion of the Gela reconfiguration project, the repair of the EST unit at the Sannazzaro site and various initiatives of plant upgrading, as well as network upgrading. The Chemical business will attract approximately €1 billion for plant upgrading and selected growth initiatives. In G&P we intend to spend approximately €0.5 billion. Finally, we will invest approximately €0.5 billion to develop photovoltaic and other renewable-related power plants in our industrial properties in Italy or in countries where we are conducting E&P operations.

Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 70 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2021 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital (“WACC”) to the Group. In 2016, management assessed that the cost of capital to the Group was marginally lower than in 2015 mainly2020 due to a ~~reduced premium for the sovereign risk incorporated into the yields~~global economic slowdown triggered by fears of pandemic disease and a failed attempt on ~~Italian ten-year bonds, partly offset by an increased volatility~~part of ~~the Eni share and an appreciation of the country risk. This latter factors~~OPEC + to support crude oil prices, management’s priorities in the perceived level of risk associated with each country of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework, as well as the consensus outlook. In 2016, our average premium for the country risk was higher than in 2015 due to a deteriorated political and financial outlook of certain countries where we are conducting upstream operations. A country risk premium is added to the Group WACC and a premium for the business risk in determining the hurdle rates, which are utilized by management in its final investment decisions.

~~Liquidity and leverage~~

~~Considering the uncertainties about future trends in market fundamentals and price volatility, management’s priorities~~short-term remain to maximize cash generation from operating activities and to preserve a solid balance sheet. We believe the initiatives implemented by management ~~during the downturn~~in recent years intended to ~~lower~~increase efficiency in operations, to reduce the ~~cost base, to optimize investments~~time-to-market of reserves and to ~~streamline operations~~restructure the mid and downstream businesses together with ~~recent~~continuing management’s focus on capital discipline and the monetization of part of our exploration ~~success~~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. Currently we are estimating that on average~~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, we will ~~be able~~capitalize on those initiatives and acquisitions to ~~fund its requirements for capital expenditures~~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 ~~cash flow~~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, ~~in a Brent price environment lower than 45 $/BBL on average~~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 in the next ~~four-year plan. We have also evaluated our~~

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~~financial resiliency considering our commitment~~four years are designed to ~~pay~~reach a ~~floor dividend~~low price of ~~€0.8 per share equating to approximately €2.9 billion per year. We estimate that in~~ the ~~2017-2020 plan~~Brent crude oil at which the Company will be able to fund through cash flow from operations both the planned organic capital expenditures and the ~~floor~~dividend. Specifically, based on these actions and on the planned underlying growth in cash generation, we expect net cash provided by operating activities to fund the planned yearly amount of organic capital expenditure and the full dividend at 60around 45 $/BBL ~~in 2017 and~~for the Brent crude, at ~~a Brent price lower than 60 $/BBL going forward. These targets are reflective~~the end of the ~~Company’s initiatives in lowering its cost base and in optimizing its capital~~ plan ~~without impairing its ability to pursue its growth objectives.~~

During the plan period, management expects to execute an asset disposal program in the range of €5-7 billion, which will comprise the dilution of interests in our exploration assets, non-strategic hydrocarbons producing assets and other marginal assets in the mid and downstream businesses. These expected cash inflows will improve the Group’s financial flexibility. These planned disposals exclude the already defined divestment of a 40% interest in the Zohr gas discovery, off Egypt, while they include the disposition of an interest in our exploration asset in Mozambique.period.

During the downturn, in spite of the sharp contraction in the operating cash flow due to lower oil prices, the Company has managed to ~~maintain~~hold its key ratio of net borrowings to equity – leverage – ~~within the~~below a preset ceiling ~~of 0.3~~ through a combination of cost cuts, asset disposals, capital expenditure curtailments and working capital ~~optimization.~~optimizations. At the end of ~~2016,~~2019, our leverage stood at ~~0.28. Management believes that~~0.24 before the target ceiling leverage is consistent with the Company’s business profile, which features an increasing exposure to the Exploration & Production segment. In 2017, we expect that the Company leverage will improve from 2016. This will be driven by the planned portfolio transactions,impact of IFRS 16 (0.36 including the ~~likely completion~~effect of ~~the Zohr divestment, and an expected reduction of 18% in the Group capital expenditure at constant exchange rates versus 2016, post portfolio transactions. This forecast is also based~~IFRS 16). The Company intends to retain a strong control on the ~~Company’s projected levels~~evolution of ~~Brent prices at which cash flow from operations is expected to fund the planned capital expenditure for the year.~~leverage going forward.

Our cash ~~flow projections~~flows from operating activities are exposed to the volatility of the oil price environment. Currently, based on our portfolio of oil&gas properties, we estimate that, holding all other factors constant, our ~~net profit and~~ cash flow from operations vary by approximately ~~€0.2~~€0.15 billion for each dollar change in Brent prices on a yearly basis compared to our price ~~forecast. We note that~~assumptions for 2020. Currently, oil prices are on a downtrend due to the ~~Brent price~~recent developments occurred until now in 2020 described in the ~~period January 1 to March 17, 2017 was approximately 55 $/BBL on average (it was 34 $/BBL on average~~above paragraph

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“Impact of COVID-19 and other current trends in the ~~period January 1 to March 31, 2016)~~oil market”. We retain some levels of financial flexibility that we may use in case oil prices should take another leg down in the cycle in the remainder of the ~~year. Particularly, approximately 37% of the planned investment~~year or in ~~the four-year plan has been allocated to projects yet to be sanctioned.~~subsequent years. In addition, we retain cash reserves and committed and uncommitted borrowing facilities.

For planning purposes, management assumed a EUR/USD exchange rate in the range of ~~1.08-1.20~~1.11 – 1.21 U.S. dollars per euro in the ~~2017-2020~~2020-2023 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, as well as a potential positive driver of the Group results of operations, cash flow and balance sheet in case the U.S. dollar appreciates against the euro.~~uncertainty. We note that in the ~~period January 1 to March 17, 2017~~first quarter 2020 the EUR/USD exchange rate was approximately ~~1.06~~1.1 and ~~appreciated year-on-year. This trend will favorably affect~~was substantially unchanged year-on-year (it was 1 EUR=1.135 USD in the ~~reported amounts~~first quarter of operating profit and operating cash flow in our Exploration & Production segment. However, the net impact of the U.S. dollar appreciation on the Group liquidity and net borrowings is uncertain as our capital expenditures are mainly denominated in U.S. dollars.2019). See “Item 3 – Risk factors”.

~~Dividend~~Remuneration policy

~~Considering the weak oil price environment, in 2015 the Company decided to rebase the annual dividend at €0.80 per share, which~~Management is ~~our floor dividend. This floor dividend has been confirmed for fiscal year 2016.~~

~~In 2017, we confirm our plan to pay a cash dividend of €0.80 per share. Going forward, we remain~~ committed to a progressive ~~distribution~~remuneration policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. ~~This forecast is dependent on~~Dividends will be driven by the results that ultimately will be achieved in implementing our strategy and ~~on management’s estimations of~~by our ability to achieve the ~~minimum level of~~targeted Brent prices at

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which the Company’s net cash ~~flows~~provided from operating activities ~~are~~is able to fund planned capital expenditures and dividend payments. ~~This projected level~~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 ~~cash neutrality~~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 ~~dependent upon achievement of our plans of profitable production growth and upgrading of profitability in mid and downstream businesses.~~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~~&gas; trends in natural gas demand in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies ~~and climates~~designed to tackle the risks of climate change in countries and regions where Eni ~~operates;~~operates or on a global scale; 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 38~~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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Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in “Item 18 – ~~note 38~~Note 27 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”.

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Contractual obligations

The amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

	Total		2017		2018		2019		2020		2021		2022 and thereafter		Total		2020		2021		2022		2023		2024		2025 and thereafter
Total debt		29,318		8,492		2,126		4,120		2,914		1,331		10,335		32,748		8,948		2,338		1,760		3,177		2,209		14,316
Long-term finance debt		23,653		2,988		2,090		4,044		2,914		1,285		10,332		21,920		2,908		1,704		1,259		2,743		1,785		11,521
Short-term finance debt		3,396		3,396												2,452		2,452
Lease liabilities																5,622		884		632		487		434		424		2,761
Fair value of derivative instruments		2,269		2,108		36		76				46		3		2,754		2,704		2		14						34
Interest on finance debt		4,007		696		557		486		386		277		1,605		3,677		594		452		353		342		269		1,667
Interest expense for lease liabilities																2,360		341		302		263		233		206		1,015
Guarantees to banks		84		84												926		926
Non-cancelable operating lease obligations(1)		2,418		593		353		257		231		199		785
Decommissioning liabilities(2)		16,281		253		580		417		400		184		14,447
Decommissioning liabilities(1)																13,474		331		325		163		179		424		12,052
Environmental liabilities		2,689		281		249		255		202		71		1,631		2,591		403		368		319		238		198		1,065
Purchase obligations(3)		120,225		10,891		9,265		9,511		8,839		7,961		73,758
Natural gas to be purchased in connection with take-or-pay contracts(4)		110,697		8,429		7,912		8,277		7,916		7,312		70,851
Natural gas to be transported in connection with ship-or-pay contracts(4)		6,620		1,569		1,053		943		724		478		1,853
Other take-or-pay and ship-or-pay obligations		724		114		105		101		96		80		228
Purchase obligations(2)																126,483		9,938		9,912		9,467		9,530		9,722		77,914
Natural gas to be purchased in connection with take-or-pay contracts (3)																120,918		7,117		9,140		8,912		9,100		9,410		77,239
Natural gas to be transported in connection with ship-or-pay contracts (3)																3,410		1,070		532		454		412		296		646
Other purchase obligations~~(5)~~		2,184		779		195		190		103		91		826		2,155		1,751		240		101		18		16		29
Other obligations~~(6)~~(4)		129		9		3		2		2		2		111		114		7		1								106
of which:
- Memorandum of intent relating to Val d’Agri		129		9		3		2		2		2		111
– Memorandum of intent relating to Val d’Agri																114		7		1								106
TOTAL		175,151		21,299		13,133		15,048		12,974		10,025		102,672		182,373		21,488		13,698		12,325		13,699		13,028		108,135

(1)

Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.

~~(2)~~

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.

~~(3)~~(2)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.

~~(4)~~(3)

Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay or ship-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Gas & Power – Natural Gas Purchases” and “Item 3 – Risk Factors – Risks in the G&P business.

~~(5)~~

~~Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States of euro 1,226 milion.~~

~~(6)~~(4)

In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to ~~defined benefit pension plans~~provisions for employee benefits (See Note 3121 to the Consolidated Financial Statements).

The table below summarizes Eni’s capital ~~expenditure~~expenditures commitments for property, plant and equipment as of December 31, ~~2016.~~2019. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown below.

	Total		2017		2018		2019		2020		2021 and subsequent years		Total		2020		2021		2022		2023		2024 and subsequent years
	(€ million)												(€ million)
Committed projects		23,756		6,733		6,679		4,218		2,441		3,685		16,448		5,570		4,054		2,611		1,544		2,669

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term finance requirements and to settle obligations.

Such a situation would negatively impact 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. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing

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requirements. The Group has also established a cash reserve, which consists of cash on hand and very

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liquid financial assets (short-term deposits and held-for-trading securities). This cash reserve according to management plans can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity over a 24-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – ~~note 38~~Note 27 of the Notes on Consolidated Financial Statements”.

As of December 31, 2016, Eni maintained short-term unused borrowing facilities of €12,308 million, of which €41 million committed. Long-term committed borrowing facilities amounted to €6,236 million, of which €700 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.3 billion were drawn as of December 31, 2016.

Working capital

Management believes that, taking into account unutilized credit facilities, ~~Eni’s~~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 due. For a description of how the Company manages the credit risk see “Item 18 – ~~note 38~~Note 27 of the Notes on Consolidated Financial Statements”.

For information about credit losses in ~~2016~~2019 and the allowance for doubtful accounts see “Item 18 – ~~note 10~~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 38~~Note 27 of the Notes on Consolidated Financial Statements”.

Research and development

For a description of Eni’s research and development operations in ~~2016,~~2019, 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 ~~March 2017:~~December 31, 2019:

Name	Position	Year elected or appointed		Age		Position	Year elected or appointed		Age
Emma Marcegaglia	Chairman		2014		51	Chairman		2014		54
Claudio Descalzi	CEO		2014		62	CEO		2014		64
Andrea Gemma	Director		2014		43	Director		2014		46
Pietro A. Guindani	Director		2014		59	Director		2014		61
Karina A. Litvack	Director		2014		54	Director		2014		57
Alessandro Lorenzi	Director		2011		68	Director		2011		71
Diva Moriani	Director		2014		48	Director		2014		51
Fabrizio Pagani	Director		2014		50	Director		2014		52
Alessandro Profumo1	Director		20152		60

Domenico Livio Trombone						Director		2017		59

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

The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on ~~May 8, 2014~~3April 13, 2017 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, ~~2016.~~2019.

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 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, Claudio Descalzi, Andrea Gemma1, Diva Moriani, Fabrizio Pagani and ~~Luigi Zingales~~4Domenico Livio Trombone were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina Litvack and Alessandro Lorenzi were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Emma Marcegaglia as the Chairman of the Board of Directors and, on ~~May 9, 2014,~~April 13, 2017, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.

~~The provisions designed to ensure gender balance were applied for the first time in the aforementioned elections.~~ Three Directors out of nine, including the Chairman, were drawn from the less represented gender, ~~thereby already~~ reaching the ratio of one-third of the Directors ~~instead of the ratio of one-fifth~~ as provided by the law for the first relevant election of the Board. The ratio of one-third of the Directors belonging to the less represented gender shall also apply to the next two subsequent terms of the Board of Directors.law.

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

Emma Marcegaglia was born in Mantua in 1965 and has been Chairman of Eni since May 2014. She has been Chairman of the 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. She is ~~President of Businesseurope and of the Luiss Guido Carli University,~~ a member of the Board of Directors of Bracco SpA and Gabetti Property Solutions SpA. From 1994 to 1996 she was National Deputy President of Young Entrepreneurs of Confindustria, from 1997 to 2000 she was President of the European Confederation of the Young Entrepreneurs (YES), from 1996 to 2000 President of Young Italian Entrepreneurs of Confindustria and from 2000 to 2002 she was Vice President of Confindustria for Europe. From May 2004 to May 2008 she

~~(1)~~

On July 29, 2015, the Board of Directors of Eni co-opted Alessandro Profumo as Director replacing Luigi Zingales, who resigned from the Board on July 2, 2015. The Director Profumo was confirmed by the Shareholders’ Meeting on May 12, 2016.

~~(2)~~

~~Alessandro Profumo was Director of Eni from May 2011 to May 2014.~~

~~(3)~~

~~(4)~~

~~Luigi Zingales resigned from the Board on July 2, 2015.~~

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was Confindustria Vice President for infrastructures, energy, transport and environment and Italian Representative of the top High Level Group for energy, competitiveness and environment set up by the European Commission. From May 2008 to May 2012 she was President of Confindustria. From July 2013 to July 2018 she was President of Businesseurope. She was a member of the Management Board of Banco Popolare and Director of Finecobank SpA and Italcementi SpA. She ~~also~~ held the position of

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 of the Aretè Onlus Foundation. From July 2010 to June 2019 she was President of the University Luiss Guido Carli. She graduated ~~with a degree~~ in ~~business administration from~~Business Administration at the Bocconi University in Milan and attended a ~~Master’s~~Master in Business Administration at New York University.

Claudio Descalzi was born in Milan and has been Eni’s CEO since May 2014. He is a member of the General ~~Board~~Council and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala. He is a member of the National Petroleum ~~Council for 2016/2017.~~Council. 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~~Board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of ~~Eni’s~~the Exploration & Production ~~Division.~~Division in Eni. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer ~~of Eni’s~~in the Exploration & Production ~~Division.~~Division of Eni. From 2010 to 2014 he held the position of Chairman of Eni UK. In 2012, Claudio Descalzi was the first European in the field of Oil&Gas to receive the prestigious “Charles F. Rand Memorial Gold Medal 2012” award from the Society of Petroleum Engineers and the American Institute of Mining Engineers. He is a Visiting Fellow at The University of Oxford. In December 2015 he was made a member of the “Global Board of Advisors of the Council on Foreign Relations”. In December 2016 he was awarded an Honorary Degree in Environmental and Territorial Engineering by the Faculty of Engineering of the University of Rome, Tor Vergata. He graduated ~~with a degree~~ in physics in 1979 from the University of Milan.

Andrea Gemma was born in Rome in 1973 and has been Director of Eni since May 2014. He is Professor of Private Law at The Third University of Rome ~~Law Department, Member~~and was visiting professor at European Universities and at Villanova University. He is member of the Strategic Board of the American University of ~~Rome and Appeal Court Lawyer and Partner in the Law and Tax Firm Gemma & Partners. He is a Member of the Studies Centre of the Chamber of Arbitration of~~ Rome. He is ~~Deputy Chairman of Serenissima SGR SpA and Chairman of the Watch Structure in Sorgente SpA. He is a member of the Board of Directors of Banca UBAE SpA and of Global Capital PLC.~~Appeal Court Lawyer. He is President of Board of Statutory Auditors of PS Reti ~~S.p.A.~~SpA and Sirti ~~S.p.A. He is a member of the Board of Directors of Cinecittà Centro Commerciale S.r.l.~~SpA. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA and Sequoia Partecipazioni ~~SpA, Corit SpA and of Sigrec SpA (Unicredit Group).~~SpA.

Pietro A. Guindani was born in Milan in 1958 and has been Director of Eni since May 2014. ~~He is currently~~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 FINECOBank SpA, Salini-Impregilo SpA and Cefriel S.cons.r.l. and~~ of the Italian Institute of Technology and Cefriel-Polytechnic of Milan. He is Board Member of ~~Civita Foundation, Assonime~~Confindustria and ~~Confindustria,~~ Member of the Executive Board of ~~Assotelecomunicazioni, member~~Confindustria Digitale; he is President of ~~the Executive Board of Confindustria Digitale~~Asstel-Assotelecomunicazioni and Vice President responsible for Universities, Innovation and Human Capital of Assolombarda. From 1982 to 1986 he was Relationship Banker at Citibank N.A. He then became International Finance Director in Montedison SpA (Enimont SpA) until 1992. He was Group Finance, Budget and Reporting Manager at European Vinyls Corporation SA/NV (1992-1993). In 1993 he became Head of Foreign Finance in Olivetti SpA. From 1995 to 2004 he was Chief Financial Officer of Vodafone Italy and of Vodafone South Europe, Middle East & Africa Region. From 2004 to 2008 he was Chief Executive Officer of Vodafone Italy. He was also Director of Société Française du Radiotéléphone – SFR S.A. (2008-2011), Pirelli & C. SpA (2011-2014), Carraro SpA (2009-2012) ~~and~~, Sorin SpA (2009-2012), Finecobank SpA (2014-2017) and Salini-Impregilo SpA (2012-2018). ~~He graduated with a degree in Business from the Università Luigi Bocconi in Milan.~~

Karina A. Litvack was born in Montreal in 1962 and has been a Director ofin Eni since May 2014. She is currently a member of the ~~Global Advisory Council of Cornerstone Capital Inc., a member of the~~ Advisory Board ofin Bridges Ventures LLC, a member of ~~the CEO Sustainability Advisory Panel of SAP AG, a member~~Board of Business for Social Responsibility, ~~and of Yachad and~~ a member of the Advisory Council for Transparency International ~~UK.~~UK, a member of the Senior Advisory Panel of Critical Resource and of the Board of Governors of the CFA Institute. She is founder and executive member of the Board of Chapter Zero Limited. 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

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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 ~~with a degree~~ in Political Economy ~~from~~at the University of Toronto and in Finance and International Business from Columbia University Graduate School of Business.

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Alessandro Lorenzi was born in Turin in 1948 and has been Director of Eni since May 2011. He is ~~a founding partner of Tokos Srl, a consulting firm for securities investment,~~Director and Chairman of ~~Società Metropolitana Acque Torino SpA and Director~~the Internal Control Committee of Ersel SIM SpA and of ~~Mutti~~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, ~~serving as a~~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 ofin Eni since May 2014. She is currently Executive Vice Chairman of Intek Group SpA, ~~CEO~~Vice Chairman of KME AG, ~~Vorstand,~~ a German holding company of KME Group, ~~Chairman~~Director of KME ~~S.r.l.,~~Srl, Member of the Supervisory Board of KME Germany GmbH and Director of Assicurazioni Generali SpA, Moncler ~~SpA, Ergycapital~~ SpA, Dynamo Academy, Dynamo Foundation and Associazione Dynamo. From 2007 to 2012 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 ~~with a degree~~ in Economics ~~from~~at the University of Florence.

Fabrizio Pagani was born in Pisa in 1967 and has been a Director ofin Eni since May 2014. He is ~~currently the~~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 ~~Technical Secretariat~~Office of the ~~Ministry~~Minister of Economy and Finance. He was Deputy Director of the International Training Programme for Conflict Management at the High School S. Anna ~~School of Advanced Studies~~ in Pisa from 1995 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. He was Senior Advisor at the OECD from 2002 to 2006, Head of the Office of the State Undersecretary, within the Prime ~~Minister’s~~Minister Office from 2006 to 2008, a 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 ~~with a degree~~ in ~~international studies from~~International Studies at the Scuola Superiore Sant’Anna, ~~School of Advanced Studies,~~ Pisa, and has a ~~Master’s Degree~~Master degree from the European University Institute, Florence.

~~Alessandro Profumo~~Domenico Livio Trombone was born in ~~Genoa~~Potenza in ~~1957~~1960 and has been Director of Eni since ~~July 2015.~~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 ~~Equita SIM, of Appeal Strategy & Finance S.r.l. and member of~~ the ~~Supervisory~~ Board of ~~Sberbank.~~Directors of Consorzio Cooperative Costruzioni-CCC, of Focus Investments SpA, of Società Gestione Crediti Delta SpA and of Prelios Credit Servicing SpA. He is, ~~also a Board member~~among the others, Director of ~~TOG “Together To Go”. In February 2012~~International World Group Srl. Furthermore, he was appointed member of the International Advisory Board of Itau-UniBanco. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey, where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development and organization projects at Bain, Cuneo e Associati (now Bain & Company). In 1991 he left the field of company consultancy to join RAS, Riunione Adriatica di Sicurtà, where as General Manager he was responsible for the banking and parabanking sectors. He was also in charge of the yield increase of RAS’s bank and of the other companies in the group operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager and was in charge of Programming and Control, becoming General Manager in 1995. In 1997 he was appointedis Chief Executive Officer of ~~Credito Italiano~~Atrikè SpA and ~~subsequently~~Sole Director of ~~Unicredit, a position~~FINCCC SpA and of Focus Investment International Srl. He is also Chairman of the Board of Statutory Auditors of Coop Alleanza 3.0 Sc, Cooperativa Immobiliare Modenese Soc. Coop., H2I SpA and of Tenute del Cerro SpA. He is standing Statutory Auditor, among the others, of: Arca Assicurazioni SpA, Arca Vita SpA, Cooperare SpA, Il Ponte SpA, Unipol Finance Srl, Unipol Investment SpA, UnipolPart I SpA and Unisalute SpA. He is Liquidator in Italcarni Sc and in Open.Co S.c. He is technical consultant in legal proceedings, coadjutor in bankruptcy proceedings, liquidator, trustee in bankruptcy and judicial commissioner. Over the years he held positions in banks, in asset management and insurance companies. More in detail, he 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 was Director of Aurora Assicurazioni SpA. From October 2007 until ~~September 2010. On an international level~~the merger of the Company in FonSai SpA, he was Chairman of the ~~European Banking Federation and Chairman~~Board of ~~the IMC~~Statutory Auditors in ~~Washington. In May 2004~~Unipol Assicurazioni SpA. Until December 2008 he was ~~decorated as Cavaliere~~Director in Banca Popolare del ~~Merito del Lavoro.~~Materano SpA and BNT Consulting

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SpA. From ~~2006~~April 2010 to ~~2014~~October 2011 he was Chairman of the Board of Directors in BAC Fiduciaria SpA. From April 2009 to December 2011 he was Chairman of the Board of Statutory Auditors in Arca Impresa Gestioni SGR SpA. From April 2007 until April 2012 he was Chairman of the Board of Statutory Auditors in Cassa di Risparmio di Cento SpA. From April 2010 to May 2016 he was Chief Executive Officer of Carimonte Holding SpA, becoming Chairman until 26 July 2018. From December 2011 to December 2012 he was independent Director in Serenissima SGR SpA. From December 2011 to April 2016 he was Director and Vice Chairman in Gradiente SGR SpA. From April 2007 to April 2016 he was Standing Statutory Auditor of Unipol Gruppo Finanziario SpA. From October 2017 to April 2019 he was Director of ~~Bocconi University in Milan and from 2011~~Aeroporto Guglielmo Marconi di Bologna SpA. From April 2013 to ~~2014 he was Director of Eni and~~July 2019 he was Chairman of the Board of Statutory Auditors in Unipol Banca Monte dei Paschi di Siena from 2012 to 2015. He was Chairman of CASL (Comitato per gli Affari Sindacali e del Lavoro dell’ABI) from 2014 to 2015 and in February 2012 he was appointed a member of the “High-level Expert Group” on structural reform of the EU banking sector; he left the Group when he was appointed Chairman of Banca Monte dei Paschi di Siena.SpA. He graduated ~~with a degree~~ in ~~business administration~~Economics from the ~~Università Luigi Bocconi~~University of ~~Milan.~~Modena.

Senior Management

The table below sets forth the composition of Eni’s Senior Management as at December 31, ~~2016.~~2019. It includes the CEO, as General Manager of Eni SpA, as well as the Chief Officers and the Executives who report directly to the CEO and to the Board, and on its behalf, to the Chairman.

Name Management position Year first
appointed
to current
position Total number
of years of
service at Eni Age
Claudio Descalzi General Manager of Eni 2014 35 61
Luca Bertelli Chief Exploration Officer 2014 32 58
Roberto Casula Chief Development, Operations & Technology Officer 2014 28 54
Alberto Chiarini Chief Retail Market Gas & Power Officer 2016 27 (1) 53
Claudio Granata Chief Services and Stakeholder Relations Officer 2014 33 56
Massimo Mantovani Chief Midstream Gas & Power Officer
2016 (2)
23 53
Massimo Mondazzi Chief Financial Officer
2014 (3)
24 53
Giuseppe Ricci Chief Refining & Marketing Officer
2016 (4)
31 58
Antonio Vella Chief Upstream Officer 2014 33 59
Marco Bollini Legal Affairs Department Senior Executive Vice President
2016 (5)
19 50
Marco Petracchini Internal Audit Department Senior Executive Vice President
2011 (6)
17 52
Roberto Ulissi Corporate Affairs and Governance Department Senior Executive Vice President Board Secretary and Corporate Governance Counsel
2006 (7)
10 54
Marco Bardazzi External Communication Department Executive Vice President 2015 1 49
Luca Cosentino Energy Solutions Department Executive Vice President 2015 13 55
Pasquale Salzano Government Affairs Department Executive Vice President
2015 (8)
5 43
Luca Franceschini Integrated Compliance Department
Executive Vice President
2016 (9)
25 50
Jadran Trevisan Integrated Risk Management
Executive Vice President
2016 (10)
16 55

~~(1)~~

~~It includes the period he served at Saipem SpA~~

~~(2)~~

~~Prior to October 17, 2016, he was Chief Legal and Regulatory Affairs.~~

~~(3)~~

~~Prior to September 12, 2016, he was Chief Financial and Risk Management Officer.~~

~~(4)~~

~~Prior to September 12, 2016 he was Executive Vice President Health, Safety, Environment & Quality Department, but he did not report to Chief Executive Officer.~~

~~(5)~~

~~Prior to October 17, 2016, he was Executive Vice President International and Finance Legal Department, but he did not report to Chief Executive Officer.~~

~~(6)~~

Since 2014 the Senior Executive Vice President of the Internal Audit Department reports hierarchically to the Board of Directors and, on its behalf, to the Chairman, without prejudice to its functional dependence on the Control and Risk Committee and on the Chief Executive Officer (in his capacity as Director in charge of the Internal Control and Risk Management System).

~~(7)~~

Since 2014, the Board Secretary has also served as Corporate Governance Counsel. The Board Secretary reports hierarchically and functionally to the Board of Directors and, on its behalf, to the Chairman.

~~(8)~~

~~Prior to February 19, 2015, he was Senior Vice President Government Affairs.~~

~~(9)~~

~~Prior to September 12, 2016, he was Executive Vice President Legal Compliance and Regulatory Department, but he did not report to Chief Executive Officer.~~

~~(10)~~

~~Prior to September 12, 2016 he reported to the Chief Financial and Risk Management Officer.~~

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Name	Management position	Year first appointed to current position	Total number of years of service at Eni		Age
Claudio Descalzi	CEO and General Manager of Eni	2014		38		64
Luca Bertelli	Chief Exploration Officer	2014		35		61
Stefano Maione	Chief Development, Operations & Technology Officer	2019		28		56
Claudio Granata	Chief Services and Stakeholder Relations Officer	2014		36		59
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
Stefano Speroni	Legal Affairs Senior Executive Vice President	2019		1		57
Marco Petracchini	Internal Audit Senior Executive Vice President	2011		20		55
Roberto Ulissi	Corporate Affairs and Governance Senior Executive Vice President and Board Secretary and Corporate Governance Counsel	2006		13		57
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
Lapo Pistelli	International Affairs Executive Vice President	2017		4		55
Luca Franceschini	Integrated Compliance Executive Vice President	2016		28		53
Jadran Trevisan	Integrated Risk Management Executive Vice President	2016		19		58

The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief ~~Midstream~~ Gas & LNG Marketing and Power Officer, the Chief Refining & Marketing ~~Officer, the Chief Retail Market Gas & Power~~ Officer, the Chief Financial Officer, the Chief Services & Stakeholder Relations Officer, Chief Digital Officer, the Senior Executive Vice President Legal Affairs, ~~Department,~~ the Senior Executive Vice President Internal Audit, ~~Department,~~ the Senior Executive Vice President Corporate Affairs and Governance, ~~Department,~~the Commercial Negotiations Senior Executive Vice President as well as the Executive Vice President Energy Solutions, ~~Department,~~ the Executive Vice President External Communication, ~~Department,~~ the Executive Vice President ~~Government~~International Affairs, ~~Department,~~ the Executive Vice President Integrated Compliance, ~~Department,~~ the Executive Vice President Integrated Risk

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Management, ~~the Chief Executive Officer of Versalis SpA and the Chief Executive Officer of Syndial SpA~~ are members of the Management Committee2, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of Committee Secretary are performed by the Senior Executive Vice President Corporate Affairs and ~~Governance Department.~~Governance.

The Chief Financial Officer has been appointed as Officer in charge of preparing Company’s financial reports pursuant to Italian law by the Board of Directors, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors.

The Senior Executive Vice President ~~of the~~ Internal Audit ~~Department~~ is appointed by the Board of Directors, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer (in his capacity as Director in charge of the internal control and risk management system), following consultation with the Board of Statutory Auditors and the Nomination Committee and with the favorable opinion of the Control and Risk Committee.

The Board Secretary and Corporate Governance Counsel is appointed by the Board of Directors upon a proposal of the Chairman.

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

Senior Managers

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

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

~~Roberto Casula~~Stefano Maione was born in ~~Cagliari in 1962.~~Avellino in1963. He ~~graduated with~~has a degree in ~~mining engineering~~Civil Engineering from the University of ~~Cagliari and joined Eni~~Bologna. Stefano Maione was hired by Agip S.p.A. in ~~1988~~1991 as a ~~reservoir engineer. He spent the first years~~Field Engineer, gaining significant experience in dynamic modelling of ~~his professional life working at oilfields~~oil fields and contributing to studies of fields in ~~Italy before moving~~Egypt and China. In 1994 he transferred to ~~West Africa~~Agip Récherches Congo S.A., again as a Field Engineer, where he ~~was appointed Chief Development Engineer. He returned~~developed his skills and experience in oil fields and eventually reached the position of Head of Field Operations. Returning to headquarters in ~~1997 as coordinator business development activities for Africa and the Middle East, contributing to a number of new initiatives and portfolio activities. In 2000,~~early 1999, he ~~became project~~occupied increasingly important roles in technical services, ~~manager~~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 ~~in 2001, moved to~~Italy. In 2007, he was elected as a member of the ~~Middle East as Project Director on a giant gas production project. From 2004 to 2005, he held a number~~Management Committee that runs Mellitah Gas B.V. Libyan Branch, 50% of ~~managerial positions in~~which is controlled by Eni and 50% by the ~~Exploration & Production Division, becoming Chief Executive Officer of Eni Mediterranea Idrocarburi SpA, engaged in oil&gas exploration and production in Sicily. At the end of 2005,~~National Oil Corporation (NOC). In January 2009, he was appointed Managing Director of ~~Eni’s activities~~Eni Iran B.V. and in 2010 returned to Libya ~~where~~as Managing Director of Eni North Africa B.V. Returning to headquarters again in January 2012, he ~~remained for two years and concluded the renegotiation of oil contracts and launched an important program of social projects. In October 2007,~~

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~~he became head of operational and business activities in sub-Saharan Africa as~~was appointed Senior Vice President ~~based~~of Development Projects and Deputy Chairman of the Development Department. He was put in ~~Nigeria. In December 2011, he was appointed~~charge of the Mozambique Programme in 2013 after Eni discovered super-giant gas fields in the country, becoming Executive Vice President ~~Africa and Middle East Region, also coordinating the Mozambique programme~~ for ~~the development of the Mamba and Coral discoveries. From 2014 to May 2016, he~~it in 2015. He was ~~a member of the Board of Directors of the Eni Foundation. Since July 1, 2014, he has been Eni’s~~appointed Chief Development, Operations & Technology ~~Officer.~~

~~Alberto Chiarini~~ was born in Milan in 1963. After taking a degree in political science and a course of specialization at the Scuola Enrico Mattei, he joined Eni in 1989. He began his career in an international context, in the business/finance area, in positions of growing responsibility in a number of countries (including the United Kingdom, Congo, Libya and Holland) rising to the position of Managing Director of Eni UK. He returned to Italy in 2006 as head of Planning and Control at the Exploration and Production division and was subsequently appointed as Eni’s Executive Vice President Global Procurement and Strategic Sourcing. In 2011 he was appointed Chief Executive of Syndial, the Eni subsidiary that provides integrated services in the field of environmental remediation. On December 6, 2013 he was appointed Chief Financial and Compliance Officer of Saipem SpA with responsibility for Finance, Legal Affairs & Compliance and ICT, overseeing in particular the recapitalisation and refinancing of the company. He was appointed as Chief Retail Market Gas & Power Officer on ~~September 12, 2016.~~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 he 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 ~~given responsibility~~made responsible for Staff and ~~Organization~~Organisation within Eni Servizi Amministrativi, a company that was set up to ~~centralize~~centralise Eni’s administrative activities.

The Committee includes also the CEOs of certain Eni’s subsidiaries.

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In 2001 he took over the management of Eni’s territorial divisions, ~~for which he structured~~restructuring the management of ~~the~~ staff by geographical area and in 2003 he took on the role of Business HR for Eni Corporate, ensuring support for ~~Departments~~departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), ~~characterized~~which was characterised by the mergers ~~by incorporation~~ of Snam and AgipPetroli and the ~~redefinition~~restructuring of ~~the organizational structures for the staff.~~staff organisation. In the same year he was also appointed ~~as Director~~head of ~~personnel~~Human Resources and ~~organization~~Organisation of ~~Sofid~~SOFID (Eni’s financial services company).

In 2006 he was appointed Human Resources Director of the E&P Division, where he oversaw the ~~Planning, Management, Development~~planning, management, development and ~~Compensation~~compensation processes for ~~the~~ human resources and organization activities. He also collaborated with the top management in the ~~reorganization~~reorganisation of macro processes for the ~~Division~~division and promoted ~~Change Management~~change management initiatives. ~~From 2006, he has been~~He became a ~~Board Member~~board member of Eni International Resources Ltd in 2006 and ~~from 2012 to 2013, he has been appointed as~~was Chairman of the ~~Board~~board of Eni International Resources ~~Ltd.~~Ltd from 2012 to 2013. From 2012 to March 2015 he ~~has been~~was a board member of Eni UK ~~Ltd. Since~~ltd.

In 2013 he ~~has been~~was appointed Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, ~~with responsibility~~responsible for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in ~~time~~“time to ~~market~~market” and efficiency. From 2014 to May 2016, he was a member of the Board of Directors of the Eni Foundation. ~~Since November 2014, he~~He has been Chairman of the ~~Board~~board of Eni Corporate ~~University. Since July 1, 2014, he~~University since November 2014. He has been ~~Eni’s~~ Chief Services & Stakeholder Relations ~~Officer.~~Officer in Eni since 1 July 2014.

~~Massimo Mantovani~~ Cristian Signorettowas born in Verona in 1974, is married and has three children. After graduating in Mechanical Engineering in 1999 from the Politecnico di Milano, he fulfilled his military service as an Officer in ~~1963. He graduated~~the Italian Army. In 2000 he was awarded with a ~~degree~~scholarship as a Ph.D. candidate at the Department of Energy of the Politecnico di Milano, where he was involved in law from the University of Milan and holds a Master’s Degree from the University of London. He is the author of numerous publications and teaches post-graduate courses. After qualifying to practice law in Italy and UK he worked for a few years in private legal practice in Milan and London. In 1993 he joined Eni’s Legal Department, specializing in international negotiations and contracts, specifically international gas/LNG supplies andresearch projects and ~~joint ventures for the commercialization and transport of gas.~~teaching activities. In 2001 he ~~was appointed legal Director of Eni’s Gas & Power Division. His main task was participating to~~joined McKinsey. He obtained a Master in Business Administration from Columbia University, New York, in 2005. After a short experience in Citigroup in New York, he continued his career in McKinsey, mostly dealing with projects in the ~~management for~~Oil&Gas and Banking&Insurance sectors. In 2007 he joined Eni in the Office of the ~~start-up phase of~~CEO supporting the ~~liberalization of the gas market in Italy~~Top Management for corporate strategy and ~~the unbundling of the national and international network for the transport of gas.~~group-level projects. In ~~October 2005~~November 2008 he was appointed Senior Vice President for International Sales with the responsibility to develop gas sales in the European B2B markets outside Italy within the Gas & Power business of Eni. In May 2012 he became Executive Vice President for International Markets and LNG Activities with the responsibility for the overall commercial strategy and sales activities outside Italy, including affiliate companies and LNG marketing. In November 2016 he became Executive Vice President for Portfolio Strategy and Long Term Gas Negotiations in the newly established Midstream business of ~~Legal Affairs~~Eni with the responsibility to oversee the gas supply portfolio management and the relationships with long term gas suppliers. In February 2018 he was appointed Executive Vice President Business Unit Gas. In this role he managed the entire midstream wholesale gas value chain, including supply and trading activities. In parallel he was also appointed EVP Trading & Origination in Eni ~~S.p.A. He has been Chief Legal and Regulatory Affairs~~Trading & Shipping SpA (the fully owned subsidiary of Eni ~~from 2014 to 2016,~~SpA in charge of all the ~~department managed all legal and energy regulatory issues of Eni and its unlisted subsidiaries. From 2005 to 2016 he was member of~~trading operations within the ~~Eni S.p.A. Watch Structure.~~group). He ~~was~~is a member of the Board of Directors ~~of Snam Rete~~in Union Fenosa Gas ~~S.p.A. from 2005 to 2012~~(Spain), a JV between Eni and ~~of the Board of the University of Bologna from 2011 to 2012.~~Naturgy, and in BlueStream (The Netherlands), a JV between Eni and Gazprom. He has been Chief Gas & Lng Marketing and Power Officer in Eni since April 15, 2019. From April 2019 he is Chairman and CEO in charge of ~~Syndial S.p.A. from 2016 to 2017. He is currently Chairman~~Gas, Lng and Power activities of Eni Trading & Shipping ~~S.p.A. He is also Eni Representative on the Eurogas Governing Board and on its Executive Committee since November 2016. Between 2011 and~~

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2014 he was a member of the anticorruption working group for the B20, coordinator for activities relating to the development of an international regulatory framework for the B20 held in Russia in 2013 and leading expert for the 2014 B20 in Australia. Massimo Mantovani has been Eni’s Chief Midstream Gas & Power Officer since 17 October 2016.SpA.

Massimo Mondazzi was born in Monza in 1963. He graduated ~~with a degree~~ in ~~economics~~Economics and ~~business administration~~Business Administration from Bocconi University Milan in 1987. He joined Eni in 1992 after acquiring considerable professional experience in industrial companies and also as a management consultant. He worked in the Administration and Control area of the Exploration and Production Division until 2006, becoming ~~head of the Division.~~Director. From 2006 to 2009 he was Director of Planning and Control for the Eni Group, before returning to E&P as Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration and Production division, to the launch of new development projects and to Eni’s entry into new countries. On December 5, 2012 he was appointed Chief Financial Officer of Eni and Officer charged with preparing the company’s financial reports pursuant to Article 154-bis of Legislative Decree No. 58/1998. He is Chairman of Agi SpA since 2013. From 2014 until September 2016, alongside his role as Eni’s Chief Financial Officer, he was also responsible for Eni’s Integrated Risk Management.

Luigino Lusuriello was born in Genoa in 1961. He joined Agip SpA’s Engineering Department in 1988 as a designer engineer of onshore and offshore structures. In 1994 he was appointed Operating and Maintenance Technologies Manager at Crema District and then he grows in the Production Area up to the

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role of Production Manager of Ortona District. In 2001 he was appointed Ortona District Manager and later Val d’ Agri District Manager. From 2004 he began an international career path, initially as Technical Director in Congo, where, the year after, he was appointed Managing Director. In 2007 he took on the role of Managing Director in ENI UK. He returned to Italy in 2009 to take on the role of Vice President for Regional Management ~~department.~~of Kazakhstan-Karachaganak activities. From 2011, following the entry of Eni in Iraq, he has been in charge for the development project as Senior Vice President of the Iraq Program. In 2013 he was appointed Executive Vice President Operations. He graduated with 110/110 in Mechanical Engineering from the University of Genoa and completed the course “The Oxford Advanced Management and Leadership Program” at the Said Business School, University of Oxford. He has been Chief Digital officer in Eni since September 18, 2018.

Giuseppe Ricciwas born in Casale Monferrato in 1958. ~~He has a degree in chemical engineering.~~ He joined Eni in 1985 initially working in the study and development of new refining processes at the Sannazzaro refinery, before becoming involved in the creation and consolidation of the joint venture with Kuwait Petroleum at the Milazzo refinery. In 2000 he returned to head office as where he was responsible for Refining Processes Development and oversaw the performance optimisation at the refining facilities of Agip Petroli. He left central technologies to take over, in 2004, as director of the Gela Refinery, a particularly challenging assignment both from a managerial perspective and in terms of the refining cycle and the complexity of the plant; in 2006 he was appointed managing director of the refinery. In June 2010 he was made Senior Vice President of the Industrial Sector for Refining & Marketing, with responsibility for the refineries, storage deposits, oil pipelines and plant and facilities in Italy, as well as the management of subsidiary and associated companies in Italy and abroad. As Industrial Director he also held a series of additional responsibilities, such as the chairmanship of Gela and Milazzo. In 2012 he took on the delicate role of Eni’s Executive Vice President Health, Safety Environment and Quality with responsibility for providing the guidelines, coordination and control of safety, industrial health, product safety, the environment and quality. ~~Since 2016 he~~He has been President of Confindustria Energia since July 2017 and President of AIDIC (Italian Association Of Chemical Engineering) since 2018. He has a ~~board member of Eniservizi.~~degree in chemical engineering. He was appointed as Chief Refining & Marketing Officer on September 12, 2016.

~~Antonio Vella~~Alessandro Puliti was born in ~~1957.~~Florence in 1963. He ~~graduated with~~joined Agip SpA’s Reservoir Department in 1990 as a ~~degree in engineering from the Turin Polytechnic in 1982~~Reservoir Geologist and ~~joined the Eni Group in 1983. He began his career as an oil engineer at Agip in Libya, where he~~ was involved in ~~upstream onshore~~the study of reservoirs in Africa and ~~offshore operations. From 1988~~Italy. His international professional career started in 1998, when he moved to ~~1991,~~Aberdeen to fill the position of Assistant Operated Asset Manager of Agip UK, where he ~~was project manager for EniChem’s petrochemical plants and refineries~~gained operational experience in ~~Italy. In 1991,~~complex contexts. After returning to Italy in 2002, he was appointed ~~project manager for~~Reservoir and Drilling and Completion Manager in the ~~development of Libyan oil fields and in 1993,~~Val D’Agri project. In 2003 he ~~moved~~was posted to Egypt ~~initially~~ as IEOC’s Development and Operations Manager and subsequently covered increasingly more complex managerial roles, first as General Manager and Managing Director of Petrobel and later as General Manager of IEOC. In 2009 he moved back to Italy to take on the role of Regional Management Russia and North Europe Vice President. In 2010, he moved to Stavanger, where he ~~was responsible for all~~held the dual role of ~~Eni’s upstream operations in Egypt.~~Eni Norge’s Managing Director and Regional Management Russia and North Europe Vice President. In ~~1999,~~2012 he returned to the HQ Operations Department, first as Senior Vice President Petroleum Engineering, Production and Maintenance and then as Senior Vice President Drilling and Completion and Deputy Operations. In October 2015 he was appointed ~~District General Manager~~Reservoir & Development Projects Executive Vice President. He graduated with Honors in Geology from the University of ~~Nigerian Agip Oil Co (NAOC),~~Milan and earned the MEDEA Master in ~~2000, became Vice Chairman~~Energy and ~~Managing Director~~Environmental Management and Economics from “Scuola Mattei”. He is the author of ~~the Eni companies in Nigeria NAOC, NAE (Nigerian Agip Exploration)~~several papers on reservoirs and ~~AENR (Agip Energy). In 2002, he became regional Vice President for Australasia, Russia, Azerbaijan and then, in 2005, a Member of the Board of Directors and Managing Director of Eni Algeria. From 2006~~drilling presented at international conferences. He was Chief Development, Operations & Technology Officer from 2018 to 2009, he was regional Senior Vice President for North Africa and the Middle East (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) for Eni’s Exploration & Production Division. In 2009, he2019. He was appointed Executive Vice President Operations for the Exploration & Production Division. In December 2012, he was appointed Executive Vice President for Central Asia, the Far East and the Pacific Area. Since July 2014, he has been a Board Member of Eni Foundation. SinceChief Upstream Officer on July 1, ~~2014, he has been Upstream Officer.~~2019.

Marco Bolliniwas born in Milan in 1966. He graduated with a degree in law from the University of Milan and he is registered to practice law on the special list of the Ordine degli Avvocati (the Italian ~~bar association)~~Bar Association) of Milan. After graduating, he worked as a lawyer for a few years in a law firm in Milan. He joined Eni in 1997 in the Legal Department of Agip ~~S.p.A.,~~SpA, mainly following international legal projects until 2001 when he took on the responsibility of International Legal Assistance of Exploration and Production Division. In 2005 he was appointed Legal Director of the Gas &Power Division, further diversifying his business knowledge. In 2007, he is back in the Exploration & Production Division as Legal

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Director. In 2008, following the centralization of the Eni’s legal function into one Legal Department, he took on responsibility for the legal assistance to the company’s activities outside Europe. In 2013 he was appointed Executive Vice President International Business Legal Area and, in 2015, he became Executive Vice President International and Finance Legal Affairs of Eni, with a strong exposure to international matters,

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with a particular focus on the Upstream business and management of partnerships and M&A transactions. ~~Since 2016, he has been~~He was a Board Member of Eni Foundation. HeFrom 2016 to 2018 he was ~~appointed~~ Senior Executive Vice President Legal Affairs of Eni. He was nominated Senior Executive Vice President Commercial Negotiations on ~~October 17, 2016.~~January 1, 2019.

Stefano Speroni was born in Milano in 1962. Stefano Speroni has accumulated vast experience in over 30 years of professional activity in the field of corporate affairs, mergers and acquisitions, private equity operations and capital markets. He has given professional support to Italian and International listed companies (in a wide range of sectors including aerospace and defence, oil & gas, telecommunications, transport and infrastructure) in strategic corporate affairs, in share trading, joint ventures and commercial agreements. From January 2016 to December 2018, he was a Managing Partner for Corporate M&A in Dentons’ Italian practice. 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 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~~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 Department.~~Audit.

Roberto Ulissi was born in Rome in 1962. ~~He’s~~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 ~~has been~~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 ~~has~~was also ~~been~~ 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 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board Member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance ~~Counsel.~~Counsel and Company Secretary. Since May 2018, he has been Coordinator of the Corporate Governance Forum of Company Secretaries.

Marco Bardazzi was born in Prato in 1967. AHe is a professional journalist ~~by trade, he worked~~working in the media ~~business~~world for 28 years before joining Eni in 2015. He has ~~achieved an~~gained extensive experience inon foreign policy and digital communications, particularly ~~related to European~~in Europe and ~~American realities (he lived and worked in the United States for nine years).~~America. Between 2009 and 2015 he ~~has been~~was Managing Editor and Digital Editor at “La Stampa”~~, a leading European newspaper based in Turin, Italy.~~. He ~~has been~~was a key member of the ~~“La Stampa”~~ team that ~~has~~ worked on ~~its~~the transformation ~~from~~of a traditional newspaper ~~founded in 1867~~ to an integrated digital news organization, ~~thus~~ creating an innovative “concentric ~~circle”~~circles” multiplatform newsroom. He ~~has also been a co-founder~~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~~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 ~~has~~ covered the ~~2000~~ Bush-Gore electoral race for the White ~~House;~~House in 2000, the first international Al Qaeda trial in ~~Manhattan;~~Manhattan, the September 11 ~~2001~~ attack on ~~America;~~America, the ~~war~~wars in ~~Afghanistan; the war in Iraq;~~Afghanistan, and Iraq and the 2004 and 2008 presidential ~~campaigns; he~~campaigns. He has visited and reported on the Guantanamo detention camp at the U.S. Navy Guantanamo Bay base ~~Cuba; he has~~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 ~~has~~reported extensively ~~reported~~ on the American digital, energy and ~~manufacturing businesses. He teaches a class on “Journalism innovation” in the Master on Journalism program at ALMED-Università Cattolica del Sacro Cuore, Milan.~~ 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 ~~16,~~ 2015, he has been External Communication ~~Department~~ Executive Vice President.

Luca Cosentino was born in Venice ~~on August 1,~~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

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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 appointed Senior Vice President Non Operated Business Performance and Stranded Resources Valorization. Since November 1, 2015, he has been Executive Vice President Energy ~~Solutions Department.~~Solutions.

~~Pasquale Salzano~~Lapo Pistelli was born in ~~Pomigliano d’Arco (Naples)~~Florence in ~~1973. In 1996, he~~1964. Having graduated with ~~Honors with a degree~~honors in ~~Law from the University “Federico II”~~1988 in ~~Naples and in 2000 obtained a PhD in international law from the University of Siena. From 1996 to 1999, he collaborated with Prof. Benedetto Conforti at the Chair of~~ International Law at the Political Science faculty “Cesare Alfieri” at the University of ~~Naples and~~Florence, he started working at a research center, while serving for two mandates in ~~2000, qualified as a Lawyer at~~ the ~~Naples Court~~local administration of ~~Appeals.~~Florence. He began his career as a diplomat in December 1999 and from January 2000 to July 2001, worked on legal and institutional issues regarding the European Union at the General Directorate for European Integrationwas member of the Italian ~~Ministry of Foreign Affairs. In 2001, in the aftermath~~Parliament from 1996 to 2015 (1996/2004 and 2008/2015), and also member of the ~~Balkan conflict, Pasquale Salzano~~European Parliament (2004/2008). As an Italian MP, he was ~~appointed Chief of Staff~~member of the ~~international OSCE Mission~~Committees on Constitutional Affairs, European Affairs and on International Affairs. As a MEP in ~~Belgrade and the following year was posted by the Italian Government to Pristina to establish and manage the Italian Liaison Office~~Brussels, he worked at the ~~Special Representative~~Economic and Monetary Affairs and Foreign Affairs Committees. During this period, he has also been the President of the ~~Secretary-General of the United Nations in Kosovo, which subsequently became the Italian Embassy. From 2005, he was in New York at the Permanent Mission of Italy to the United Nations~~EU-South Africa Delegation and ~~after about two years, was posted to Rome to the Office of the Diplomatic Adviser to the Prime Minister where, in view~~a member of the Italian ~~Presidency of~~Delegation to the ~~G8, was appointed by the Prime~~OSCE, where he conducted several monitoring missions in transitional democracies.

He served as Deputy Minister as Head of the Sherpa Office for the G8/G20. In 2009, he was selected by the OECD Secretary-General as Director of the Heiligendamm/L’Aquila Process in Paris. From January 2011, he was seconded by the Ministry 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 ~~where he was appointed~~as Senior Vice President ~~International Institutional Relations~~for Strategic Analysis for Business Development Support. 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 ~~the Department of Institutional Relations and Communications and Vice President of Eni-USA’s Representative office. He is~~international relations. Among other things, he’s a ~~Young Global Leader~~member of the ~~World Economic Forum, is a Member~~Council of Chatham house, member of the ~~Board~~board of the European Council on Foreign Relations (ECFR) ~~Italy, the Scientific Committee~~and of the ~~Rome-Mediterranean Foundation and the National Assembly of UNICEF Italy. He is a~~Istituto Affari Internazionali (IAI), member of the ~~Institute for International Affairs (IAI)~~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 ~~Institute for International Political Studies (ISPI). From July 1, 2014 to 2015 he~~Middle East. He was ~~Eni’s Senior Vice President Government Affairs. Since February 19, 2015, he has been Eni’s~~appointed Executive Vice President ~~Government~~of International Affairs ~~Department.~~on April 14, 2017.

Luca Franceschiniwas born in Milan in 1966. He ~~graduated with~~is a ~~degree~~graduate in ~~law~~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)~~Bar Association) in ~~Rome.He~~Rome. He first joined in Eni in 1991 in the legal department of Agip ~~S.p.A.,~~SpA, initially involved in disputes and providing legal assistance to the procurement area, before going on to delivering legal support for a range of national and international projects in the Exploration & Production sector. In 2000, in the context of the process for the liberalisation of the natural gas sector, he was involved in the spin-off of the gas storage business and the creation and launch of Sogit SpA, for which he became head of Legal and Corporate Affairs. He made his return to Eni ~~Spa~~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 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 of the Refining & Marketing sector. He was also

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a member of the boards of directors of both Italgas and Stogit. InFrom 2015 to 2016 he was ~~appointed as~~ Eni’s Executive Vice President for Legal and Regulatory Compliance. He was appointed as Executive Vice President of Integrated Compliance on September 12, 2016. He is also a member of the Watch Structure of Eni SpA. In 2017 he was awarded “Compliance Officer of the Year” by the Top Legal Corporate Counsel Awards and the Inhouse Community Awards.

Jadran Trevisan was Born in Milan in 1961. He has a degree in philosophy and a Master’s in business administration from SOGEA, the management school of Confindustria Liguria. After a short period at Gabetti, in 1991 he joined the Fininvest Group, where he was involved in financial communications and was part of the project for the listing of Mediaset for which, in 1995, he became the Investor Relations Manager. In 2000 he joined Eni as head of Investor Relations, where, in addition to participating in a number of significant extraordinary operations (the listing of Snam Rete Gas, the de-listing of Italgas), he oversaw relations with institutional investors. In 2006 he was appointed head of Business Strategy at Eni’s E&P division, where he was involved in the acquisition of significant assets and companies operating in the upstream sector. In 2008 he was appointed CFO of the recently acquired subsidiary Distrigas, where, for

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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. Since March 18, 2019, he is also responsible of identification, evaluation and monitoring Eni industrial and contractual risks processes.

Compensation

Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of Directors, which considers relevant proposals made by the Compensation Committee after consultation with the Board of Statutory Auditors.

~~Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter~~ ~~of Legislative Decree No. 58 of February 24, 1998 and Article 84-quater~~ of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications) and in line with the Corporate Governance Code recommendations for Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy Guidelines adopted for Directors and other Managers with strategic responsibilities5.

The main elements of the 2017 remuneration policy and of the compensation paid in 2016 to Directors, Statutory Auditors, CEO and General Manager and other Managers with strategic responsibilities, are described below.

~~2017 Remuneration Policy Guidelines~~

This chapter contains the Remuneration Guidelines for the new 2017-2020 term, approved by the Board of Directors on February 28, 2017 for the Directors who will be appointed at the Shareholders’ Meeting on April 13, 2017. The new Board of Directors will retain the prerogative to determine, specific remuneration for the exercise of delegated powers and for participating on Board Committees, based on a proposal by the Compensation Committee. The Shareholders’ Meeting will retain the prerogative to approve the Share-based Variable Incentive Plans.

Furthermore, the Remuneration Guidelines below for Directors in office until April 13, 2017 are also briefly outlined. These were already extensively discussed in the Remuneration Report 2016 and reflect the decisions made by the Board of Directors on May 28, 2014 for the 2014-2017 term.

~~Policies For Directors During The 2017-2020 Term Of Office~~

The main novelty of the Remuneration Policy in the new term of office is the comprehensive review of the variable incentive scheme for the Chief Executive Officer and General Manager and for all other Senior Managers in order to simplify the incentive scheme’s overall architecture (which will be broken down into two incentive plans instead of three) and further align performance objectives with shareholder expectations. More specifically, the new incentive scheme provides for the introduction of:

•

a Short-Term Monetary Plan with the deferral of a portion of the accrued bonus, which will start from the assignment of the 2017 objectives with the first payment in 2018, to replace the previous Annual Monetary Incentive and Deferred Monetary Incentive plans.

•

a Long-Term Performance Share Plan 2017-2019, with first attribution in 2017, to replace the previous Long-Term Monetary Incentive Plan (subject to approval by the Shareholders’ Meeting on April 13, 2017).

~~(5)~~

Those persons who have the power and responsibility, directly or indirectly, for planning, directing and controlling Eni fall under the definition of “Managers with strategic responsibilities”, pursuant to Consob regulations. Eni Managers with strategic responsibilities, other than Directors and Statutory Auditors, are those who sit on the Management Committee and, in any case, those who report directly to the Chief Executive Officer.

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For the Chairman and the Non-Executive Directors, adjustments are proposed for the remuneration envisaged for delegated powers and for participating on Board Committees compared with median levels in the reference markets.

~~Market references and peer group~~

For the Chief Executive Officer and General Manager, the positioning of the Company’s remuneration is assessed by comparing similar roles only in the international Oil & Gas sector, with regard to upstream activities in particular, and in line with the company’s strategy to increase its focus on the business. More specifically, the comparator group has been expanded to include the main listed companies in the Oil & Gas sector, which are Eni competitors at the international level and possess comparable business characteristics (Anandarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total).

~~This panel also constitutes the Peer Group used for the relative comparison of Eni performance in the new Long-Term Performance Share Plan.~~

For the Chairman and the Non-Executive Directors, the positioning of remuneration is assessed by comparing similar roles in the Top Italy Panel, composed of the main companies listed on the FTSE MIB (Assicurazioni Generali, Atlantia, Enel, Intesa Sanpaolo, Leonardo-Finmeccanica, Luxottica, Mediaset, Mediobanca, Poste Italiane, Snam, Terna, TIM, Unicredit).

For Managers with strategic responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector.

~~General principle of clawback~~

Clawback mechanisms will be adopted, through a specific regulation proposed by the Compensation Committee and approved by the Board of Directors, allowing the variable remuneration components already paid and/or granted to be reclaimed, or those subject to deferral to be withheld, where their achievement was based on data that was subsequently proven to be manifestly misstated, or allowing the recoupment of all the incentives for the year (or years) in which subsequent checks confirm the fraudulent alteration of the results data used to obtain the right to incentives, and/or the commission of serious and deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to the employment and trust relationship, without prejudice to any other action permitted by law and regulations to protect the interests of the Company. The regulation provides that the activation of recoupment claims (or revocation of incentives awarded but not yet paid) must take place, once the checks have been completed, within three years of payment (or award) in the case of error, and within five years in the case of fraud.

~~Chairman of the Board of Directors~~

~~Remuneration for the delegated powers~~

~~Remuneration will be defined in line with the decisions taken by the Shareholders’ Meeting on 13~~th ~~April 2017 and with the median levels in the reference market, taking the delegated powers into account.~~

~~Payments due in the event of termination of office or employment~~

~~No specific severance payments are provided for the Chairman, nor do any agreements exist for indemnities in the case of early termination of office.~~

~~Non-executive directors~~

~~Remuneration for participation on Board Committees~~

The Policy Guidelines for Non-Executive and/or Independent Directors provide for the adjustment of the additional annual remuneration for participating on Board Committees in line with the median levels in the reference market, taking due account of commitment in terms of meetings and their duration. More specifically, for the 2017-2020 term, the following remuneration is proposed:

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•

~~for the Control and Risk Committee, annual remuneration consists of €70,000 for the Chairman and €50,000 for the other members;~~

•

~~for the Compensation Committee and the Sustainability and Scenarios Committee, the annual remuneration consists of €50,000 for the Chairman and €35,000 for the other members;~~

•

~~for the Nomination Committee, the annual remuneration consists of €40,000 for the Chairman and €30,000 for the other members.~~

~~Payments due in the event of termination of office or employment~~

~~No specific severance payments are provided for the Non-Executive Directors, nor do any agreements exist for indemnities in the case of early termination of office.~~

~~Chief Executive Officer and General Manager~~

The Policy Guidelines for the Chief Executive Officer and General Manager take into account the specific delegated powers granted in accordance with the By-laws, the instructions contained in the chapter “Purpose and general principles of the Remuneration Policy” as well as the remuneration levels and best practices in the reference Oil & Gas panel.

~~Fixed remuneration~~

Fixed remuneration (FR) will be set by the new Board of Directors based on a proposal of the Compensation Committee in relation to the delegated powers and positions held, taking into account the median levels in the reference market. Fixed remuneration includes the remuneration for Directors established by the Shareholders’ Meeting on April 13, 2017, as well as any compensation that may be due for participating on the Board of Directors of subsidiaries or associated companies.

~~Variable incentive plans~~

~~Short-Term Monetary Plan with deferral~~

~~The new Short-Term Monetary Plan with deferral of a portion of the accrued bonus brings together the previous Annual Monetary Incentive and Deferred Monetary Incentive plans.~~

~~Compared with the previous Plans, the performance scales have been extended to include achievement of results that are above or far above the target levels.~~

~~In this Plan, a portion of the incentive is paid annually and a portion is deferred for a three-year period, as described below.~~

The Short-Term Monetary Plan with deferral is linked to the achievement of the 2017 objectives approved by the Board of Directors on February 28, 2017. These objectives keep the structure focused on the essential goals consistent with the guidelines outlined in the Strategic Plan and balanced against the interests of the various stakeholders, in terms of economic and financial results (25%), operating results and sustainability of the economic performance (25%), environmental sustainability and human capital (25%), efficiency and financial strength (25%). The value of each objective, at target performance level, is aligned with the budgeted value.

Each objective is measured in accordance with a performance scale of 70 to 150 points (target=100), in relation to the weight assigned to each target (below 70 points, the performance of each target is considered to be zero). For the purposes of the incentive award, the minimum overall performance is 85 points. This Plan provides for remuneration calculated with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) multiplier, equal respectively to 85%, 100% and 150% to be applied to the target incentive, as determined by results achieved by Eni over the previous year.

~~Total incentive (TI) is calculated using the following formula:~~

~~TI = FR x % ITarget~~ ~~x Multiplier~~

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~~Where “ITarget” is the incentive percentage at target performance level, which is set at 150% of total fixed remuneration for the Chief Executive Officer.~~

~~The Plan conditions state that the total incentive is divided into 2 portions.~~

~~a portion paid annually (IYear) equal to 65% of the total incentive.~~

I~~annual~~ ~~= TI x 65%~~

~~The levels of the fraction of the incentive payable during the year, depending on the performance levels achieved, are shown in the table below.~~

Annual
performance <85 85 100 150
threshold target max

Annual incentive
(% of Fixed Rem)
0% 83% 98% 146%

~~a deferred portion equal to 35% of the total incentive, subject to further performance conditions during a three-year vesting period.~~

The deferred portion payable at the end of the vesting period is determined by multiplying the initial deferred portion by the payment multiplier. The latter is given by the average of the three annual multipliers, each determined during the three-year period in relation to the performance achieved, based on Eni’s annual objectives. The multiplier of the deferred portion depends on the performance achieved, with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) incentive level, equal respectively to 85%, 130% and 230% of total fixed remuneration.

~~The Deferred Incentive (DI) payable at the end of the three-year deferment period is calculated using the following formula:~~

~~DI = TI x 35% x Multiplier~~

~~The levels of the payable deferred portion, depending on the performance levels achieved throughout the three-year period, are shown in the table below.~~

3-year Average performance <85 85
threshold 100
target 150
max

Deferred incentive
(% of Fixed Rem)
0% 38% 68% 181%

~~Long-Term Performance Share Plan~~

The Chief Executive Officer participates in the Long-Term Performance Share Plan 2017-2019, which also applies to Senior Managers, deemed critical for the business, subject to approval by the Shareholders’ Meeting on April 13, 2017.

The Plan replaces the previous Long-Term Monetary Incentive Plan as a tool to incentivize and promote the loyalty of the most critical management positions for the company, ensuring achievement, in line with international best practices, of the following additional objectives:

•

~~strengthening the culture of business risk management from the perspective of shareholders by adopting shares as an incentive;~~

•

~~setting a more challenging minimum incentive threshold, positioned at median level;~~

•

~~further aligning performance conditions with the long-term expectations of shareholders, using:~~

~~(i)~~

an assessment of the performance of the Company’s Total Shareholder Return over a three-year period compared with that of the Reference Stock Market Index, compared with the same performance of the main international competitors (Peer Group);

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~~(ii)~~

further incentivize the capacity to develop industrial assets, measured using the increase in the Net Present Value of hydrocarbon reserves in the medium-long term (in accordance with the assessment method defined by the SEC), measured in relative terms compared with the designated peer group.

~~The Plan provides for three annual awards starting from 2017, each with a three-year vesting period.~~

~~The Plan is subject to performance conditions during the three-year vesting period, in accordance with the following parameters and related weightings:~~

The difference between the TSR of Eni Shares and the TSR of the FTSE MIB index of Borsa Italiana, corrected by the Eni Correlation Coefficient, compared with the equivalent adjusted TSR measure for each company in the Peer Group, as shown in the following (50% weight):

~~TSR~~A ~~- (TSR~~I ~~x ρ~~ ~~A,I~~)

~~Where:~~

~~TSR~~A~~: TSR of Eni or one of the companies in the Peer Group~~

~~TSR~~I~~: TSR of the Reference Stock Market Index of the company for which TSR~~A ~~was calculated~~

ρ ~~A,I: Correlation Coefficient~~

~~Net Present Value of proven reserves (NPV) vs the Peer Group, measured in terms of the annual percentage change, calculating the average annual performance in the three-year period (50% weight).~~

~~The reference Peer Group is described in the “Market references and Peer Group” section. (Anadarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total).~~

~~For the Chief Executive Officer and General Manager, the Plan conditions provide for the annual award of shares for a value equivalent to 150% (Itarget) of total fixed remuneration, using the following formula.~~

	~~No.of Attributed Shares =~~			~~FR x % Itarget~~
				~~PriceAttr~~

~~Where the price of the award (PriceAttr~~) is calculated as the average of daily official prices (source Bloomberg) recorded in the 4 months before the date of the Board of Directors meeting that annually approves the plan rules and the award to the Chief Executive Officer and General Manager.

The granting of shares at the end of the three-year vesting period is determined using a final multiplier to be applied to awarded shares (calculated as the weighted average of the multipliers of each parameter) determined over the vesting period in relation to the position reached in the peer group.

~~Each multiplier may be between 0 and 180%, with a threshold set at the median level, in accordance with the scale shown below.~~

Performance Scale - Multiplier
Ranking
1st 2nd 3rd 4th 5th 6th 7th 8th 9th 10th 11°
Multiplier
180% 160% 140% 120% 100% 80% 0% 0% 0% 0% 0%
Median
positioning

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~~Grantable shares are calculated using the following formula:~~

~~No.of Granted Shares = No.of Attributed Shares x Multiplier~~

~~The value levels of the Shares granted at the end of the vesting period, net of changes in the share price over the same period, are given below.~~

Weighted average 3-year performance <26.6 26.6
threshold (*) 100
target 180
max

Value of Shares
(% of Fixed Rem)
0% 40% 150% 270%

~~(*)~~

~~Achieved for example if the minimum level (6th place) is reached for the indicator of NPV of proven reserves, in at least two years of the three year vesting period.~~

~~For executives in services, 50% of the shares granted at the end of the vesting period are locked up for a period of 1 year after the grant date.~~

~~As the Plan is submitted to the Shareholders’ Meeting for approval, it is also described in detail in the~~ information ~~document made available to the public on the Company website.~~

For both the deferred portion of the short-term incentive and the long-term share incentive, the clauses provided for all Managers in the respective Rules will apply in cases of termination of employment before the end of their term of employment. If their contract is not renewed, the natural expiry of the related vesting period is retained, in accordance with the performance conditions defined by each Plan.

~~Benefits~~

For the Chief Executive Officer and General Manager, the Policy Guidelines provide for insurance coverage for the risk of death or permanent disability and, as per provisions contained in the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the supplementary pension plan (“~~FOPDIRE”) as well as in the supplementary health plan (FISDE ), together with a company car for business and personal use.~~

~~Pay Mix~~

The remuneration package for the Chief Executive Officer and General Manager includes a fixed component, a short-term variable component and a long-term variable component, composed of the short-term incentive deferral and the long-term share incentive valued using the international methodologies adopted for remuneration benchmarks.

~~The pay mix, calculated by considering fixed remuneration as the base, is significantly focused on the variable components, with a dominant weighting attributed to the long-term component.~~

~~Payments due in the event of termination of office or employment~~

For the Chief Executive Officer and General Manager, in line with reference practice and with the provisions of the European Commission Recommendation No. 385 of April 30, 2009, as well as to protect the Company from potential competitive risks, the Policy provides for following payments:

•

An indemnity supplementing the severance award payable upon termination of the employment relationship, due to non-renewal or early termination of the 2017-2020 term of office, including in the event of resignation due to a substantive reduction of delegated powers. Compensation for the CEO position will be defined in line with European Recommendations. For any employment relationship, the provisions set out for Managers with Strategic Responsibilities shall apply. Also with reference to criteria 6.C.1.g of the Italian Corporate Governance Code, thisconcerning compensation is not due in the event of dismissal for “just cause” under Art. 2119 of the Italian Civil Code, or in the event of resignation as Chief Executive Officer prior to the expiry of the term in office, unless triggered by either the above-noted reduction of delegated powers, or in the event of death as governed by Art. 2122 of the Italian Civil Code;

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•

Any non-competition agreement to protect the Company’s interests, with specific compensation as a proportion of annual remuneration, as well as in relation to the rules of application, extent and duration of the commitments.

~~Policies for Directors during the 2014-2017 term of office~~

~~The Policy Guidelines for the term of office that expires at the Shareholders’ Meeting on 13th April 2017 are summarized below.~~

~~Chairman of the Board of Directors~~

~~Remuneration for delegated powers~~

A fixed remuneration for the delegated powers of €148,000 is provided for the Chairman of the Board of Directors, in addition to remuneration for the position determined by the Shareholders’ Meeting on May 8, 2014, amounting to €90,000, in compliance with the maximum of €238,000 defined by the same Shareholders’ Meeting. These Guidelines do not provide for variable remuneration.

In 2017, these remuneration components will be paid pro-rata with respect to the period in office that ends with the Shareholders’Meeting called to approve the Financial Statements as at December 31, 2016.

~~Payments due in the event of termination of office or employment~~

~~No specific severance payments are envisaged for the Chairman, nor do any agreements exist for indemnities in the case of early termination of office.~~

~~Benefits~~

~~The Chairman is granted insurance coverage for the risk of death or permanent disability.~~

~~Non-executive Directors~~

~~Remuneration for participation on Board Committees~~

~~Non-executive and/or Independent Directors receive an additional annual remuneration~~6 ~~for participating on Board Committees, as follows:~~

•

~~for the Control and Risk Committee, the remuneration amounts to €60,000 for the Chairman and €40,000 for the other members;~~

•

~~for the Compensation Committee, the Sustainability and Scenarios Committee and the Nomination Committee the remunerations amount to €30,000 for the Chairman and €20,000 for the other members.~~

~~In 2017, this remuneration will be paid pro-rata with respect to the period in office that ends with the Shareholders’ Meeting of April 13, 2017.~~

~~Payments due in the event of termination of office or employment~~

~~No specific severance payments are provided for the Non-Executive Directors nor do any agreements exist that provide for indemnities in the case of early termination of office.~~

~~Chief Executive Officer and General Manager~~

For the Chief Executive Officer and General Manager, the Policy Guidelines reflect the resolutions passed by the Board of Directors on May 28, 2014, taking into account the specific delegated powers granted in accordance with the Articles of Association, the instructions contained in the chapter “Principles and general purposes of Eni Remuneration Policy”, as well as the 25% reduction of the

~~(6)~~

~~This remuneration supplements the one established by the Shareholders’ Meeting of May 8, 2014, for the remuneration of Non-executive Directors, amounting to €80,000 annual gross.~~

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maximum payable overall remuneration of the previous mandate, in accordance with the Shareholders’ resolution of May 8, 2014. The remuneration envisaged by the Board in relation to the delegated powers includes both the compensation for Directors determined by the Shareholders’ Meeting on May 8, 2014, as well as any compensation that may be due for participating on the Board of Directors of Eni’s subsidiaries or associated companies.

~~Fixed remuneration~~

For the Chief Executive Officer and General Manager total fixed remuneration is set at a gross annual amount equal to €1,350,000, of which €550,000 for the position of Chief Executive Officer and €800,000 for the position of General Manager.

The remuneration envisaged by the Board in relation to the powers delegated includes both the remuneration for Directors determined by the Shareholders’ Meeting on May 8, 2011, as well as any compensation that may be due for participating on the boards of directors of Eni’s subsidiaries or associated companies.

~~In 2017, these remuneration components will be paid pro-rata with respect to the period in office that ends with the Shareholders’ Meeting of April 13, 2017.~~

In his capacity as Eni Senior Manager, the General Manager is also entitled to receive an allowance for travel, in Italy and abroad, in line with the applicable provisions provided by the relevant national collective labor agreement for senior managers and complementary Company level agreements.

~~Annual variable incentives~~

~~The annual variable incentive linked to achieving the targets set for 2016 will be paid in 2017.~~

~~Deferred Monetary Incentive Plan~~

In 2017, the Chief Executive Officer and General Manager participates in the last award of the Deferred Monetary Incentive (DMI) Plan 2015-2017, also envisaged for all the Company’s senior managers, associated with Company performance measured in terms of Earnings Before Taxes (EBT).

~~Long-Term Monetary Incentive Plan~~

The Long-Term Monetary Incentive Plan 2014-2016 ended in 2016 with the last award. The new Long-Term Performance Share Plan 2017-2019 will be implemented from 2017. This Plan has already been described in the section “Policies for the 2017-2020 term of office” and in the information document made available to the public on the Company website.

~~Benefits~~

For the Chief Executive Officer and General Manager the Policy Guidelines provide for insurance and healthcare coverage defined by the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, as well as a company car for business and personal use.

~~Payments due in the event of termination of office or employment~~

For the Chief Executive Officer and General Manager, in line with sector practices and with the provisions of the European Commission Recommendation No. 385 of April 30, 2009, as well as to protect the Company from potential competitive risks, the Policy provides for following payments:

•

an indemnity supplementing the severance award, with mutual exemption from notice, is payable upon termination of the employment relationship, due to non-renewal or early termination of the 2014-2017 term of office, including in the event of resignations caused by a substantial reduction of delegated powers. This indemnity is equal to two years of total fixed remuneration (€1,350,000), for a total gross amount equal to €2,700,000. It should also be noticed that there is an ongoing analysis of the effective enforceability of the agreed framework, partly with reference to legislative changes following the conclusion of the contract with the Chief Executive Officer and General Manager. Also with reference to the recommendation 6.C.1g) of the Italian

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Corporate Governance Code, note that, in relation to the applicable contractual provisions, this compensation is not due in case of dismissal for “just cause” under Article 2119 of the Italian Civil Code or in cases of resignations as Chief Executive Officer before the expiry of the term in office , unless triggered by a reduction of delegated powers, or in the event of death governed by Article 2122 of the Italian Civil Code;

•

non-competition agreement to protect the Company’s interests that can be activated at the sole discretion of the Board of Directors through the exercise of an option right, the validity of which applies only as of the one set of a second term (if appointed), in exchange for a total option fee of €500,000 gross to be paid in three annual installments. If the option is exercised by the Board and the agreement is implemented, a non-compete award will be paid subject to a commitment by the Chief Executive Officer and General Manager not to undertake, for the twelve months following the expiry of the term, any activities of Exploration & Production activities potentially in competition with Eni in key markets in Europe, America, Asia and Africa. This amount will be set by the Board of Directors as the sum of two components: (i) a fixed component of €1,500,000; and (ii) a linearly determined variable component based on the average annual performance of the previous three years (equal to 0 for performance below or equal to the target and to €750,000 for maximum performance), and will be paid at the expiry of the term of the agreement. The variable component is calculated by taking into consideration the annual performance related to the annual Variable Incentive Plan. Any violation of the non-competition agreement will result in the non-payment of the consideration (or its restitution, where the violation is identified by Eni after the payment), and the obligation to pay damages set by mutual agreement in an amount equal to twice the amount of the non-competition agreement, without prejudice to Eni’s right to seek fulfillment in specific form.

~~2017 policies for MANAGERS WITH STRATEGIC RESPONSIBILITIES~~

For Managers with Strategic Responsibilities, the Guidelines provide for remuneration plans that are strictly in line with those of the Chief Executive Officer and General Manager, to better guide and align managerial action with the objectives set out in the Company’s Strategic Plan, and with the provisions and protections laid down by the national collective bargaining agreement for senior managers.

In the new 2017-2020 term of office, starting from April 13, 2017, the new Long-Term Share Incentive Plan and Short-Term Variable Incentive Plan with Deferral – intended for the Chief Executive Officer who will be appointed by the Shareholders’ Meeting of April 13, 2017 - will also apply to Managers with Strategic Responsibilities. The Plans applying to the previous term will be implemented until April 13, 2017.

~~Market references~~

For Managers with Strategic Responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector.

~~Fixed remuneration~~

Fixed remuneration is based on the role and responsibilities assigned, taking into consideration a graduated and a generally median to below-median positioning versus national and international executive markets for comparable roles. It may be updated periodically during the annual salary review for all managers.

~~Given current market comparators and trends, the 2017 Guidelines provide for a selective approach to salary reviews, while maintaining appropriate levels to ensure competitiveness and motivation.~~

More specifically, the proposed actions will include measures to adjust fixed/one-off remuneration for those in positions that have seen a significant increase in responsibility or scope, and to reflect needs for retention and excellent performance.

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In addition, as Eni officers, Managers with Strategic Responsibilities are entitled to receive the allowances due for travel in Italy and abroad, in line with applicable provisions of the relevant national collective bargaining agreement for senior managers and supplementary Company agreements.

~~Variable incentive plans~~

~~Annual variable incentives~~

Starting with the assignment of the 2017 objectives and with the first payment in 2018, the annual variable Incentive Plan will be replaced by the new Short-Term Monetary Plan with deferral, already described for the Chief Executive Officer and General Manager.

The targets set for Managers with Strategic Responsibilities are consistent with those assigned to the Chief Executive Officer and General Manager, on the basis of the same perspective of stakeholder interests, as well as with the relevant individual targets, consistent with the responsibilities of the role played and the provisions of the Company’s Strategic Plan. For Managers with Strategic Responsibilities the target incentive levels for the new Short-Term Monetary Plan differ depending on the role’s level of responsibility and complexity and are equal to the sum of those set for the previous Annual Variable Incentive Plan and Deferred Monetary Incentive Plan (up to 100% of fixed remuneration).

The last award for the previous Annual Variable Incentive Plan will be paid in 2017, determined with reference to the performance goals set for Eni, the business area and individual performance in 2016.

~~Deferred Monetary Incentive Plan~~

~~Managers with Strategic Responsibilities participate in the last attribution of the Deferred Monetary Incentive Plan (DMI) 2015-2017, approved by the Board of Directors on March 12, 2015.~~

~~Long-term variable incentive plan~~

Managers with Strategic Responsibilities participate in the Long-Term Performance Share Plan (LTI) 2017-2019, approved by the Board of Directors on February 28, 2017 and submitted for approval by the Shareholders’ Meeting on April 13, 2017.

The Plan is directed at managers who are critical for the business and envisages three annual awards, starting in 2017, with the same performance conditions and characteristics as those described above for the Chief Executive Officer and General Manager.

For Managers with Strategic Responsibilities, the value of the shares to be awarded each year differs depending upon the level of their role and is limited, as in the previous long-term monetary incentive plan, to a maximum of 75% of fixed remuneration.

~~Benefits~~

For Managers with Strategic Responsibilities, in line with the policy implemented in 2016 as well as the provisions of the national collective bargaining agreement and supplementary Company-level agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE) and health plan (FISDE), as well as insurance coverage for the risk of death or disability, together with a company car for business and personal use, and the possible assignment of housing based on operational and mobility requirements.

~~Pay Mix~~

The average target pay mix of the remuneration package for Managers with Strategic Responsibilities, with the application of both new incentive plans (short-term monetary plan with deferral and long-term performance share plan), calculated using the same valuation methods used for the Chief Executive officer and General Manager, highlights the balance between the fixed and variable components and, as regards the latter, the greater weighting of medium-long term variable incentives, in line with market best practice.

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~~Payments due in the event of consensual termination of employment~~

Managers with Strategic Responsibilities, as well as Eni senior managers, are entitled to the severance benefits for employment termination established by law and applicable national collective bargaining agreement, together with any termination indemnities agreed on an individual basis, in accordance with the criteria established by Eni for cases of early termination, within the limits of the protection envisaged by the applicable national collective bargaining agreement, and consistent with application criterion 6.C.1 lett.g) of the Italian Corporate Governance Code. These criteria take into account the position held, the retirement age and actual age of the manager at the time employment is terminated and the annual remuneration received. For cases of termination that present high competitive risks relating to the criticality of the position held by the Manager, agreements containing non-competition clauses may also be entered into with payments defined in relation to the remuneration received and the scope, duration and effectiveness of the agreement.

~~COMPENSATION AND OTHER INFORMATION~~

~~Implementation of the 2016 remuneration policies~~

The following is a description of the remuneration decisions taken in 2016 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, and other Managers with strategic responsibilities, in relation to their time in office.

The implementation of the 2016 Remuneration Policy, as verified by the Compensation Committee at the regular assessment required by the Corporate Governance Code, was found to be consistent with the 2016 Remuneration Policy, approved by the Board of Directors on March 17, 2016. This takes into account the resolutions passed by the Board of Directors on May 9 and May 28, 2014 on the remuneration of Non-executive Directors appointed Board Committees and on the definition of the remuneration of Directors with delegated powers, in accordance with the resolutions passed at the Shareholders’ Meeting in accordance with Law No. 98/2013.

~~Chairman of the Board of Directors - Emma Marcegaglia~~

~~Fixed remuneration~~

The Chairman was paid the fixed remuneration approved for the office by the Shareholders’ Meeting of May 8, 2014 of €90,000 gross and the remuneration approved by the Board of Directors Meeting of May 28, 2014, in relation to the exercise of delegated powers, amounting to €148,000 gross.

~~Benefits~~

~~The Chairman was granted insurance coverage against the risk of death and permanent disability, in accordance with the resolutions of the Board of Directors Meeting of May 28, 2014.~~

~~Non-executive Directors~~

The Directors were paid fixed remuneration approved by the Shareholders’ Meeting of May 8, 2014 of €80,000 gross. The additional remunerations payable for participation on the Board Committees, as resolved by the Board of Directors Meeting of March 12, 2015, were also paid.

~~Chief Executive Officer and General Manager - Claudio Descalzi~~

Claudio Descalzi has held the office of Chief Executive Officer and General Manager since May 9, 2014, and before then he held the office of Chief Operating Officer (COO) of the E&P Division. Therefore, during 2016, Claudio Descalzi received the fixed remuneration and the annual variable incentive related to his current role of Chief Executive Officer and General Manager and the long term variable incentives accrued during his previous role, as detailed below.

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~~Fixed remuneration~~

The Chief Executive Officer and General Manager was paid the fixed remunerations approved by the Board of Directors Meeting of May 28, 2014, which also include the remunerations approved by the Shareholders’ Meeting for all the Directors, equal to a total gross annual amount of €1,350,000.

~~Annual variable incentives~~

In line with the Remuneration Policy 2016, the Chief Executive Officer and General Manager was paid a gross annual variable incentive of €1,755,000 associated with the performance achieved during 2015 (130 points).

~~Deferred Monetary Incentive Plan~~

For the Chief Executive Officer and General Manager, the Board of Directors as its meeting of March 17, 2016, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2016, approved the assignment of the deferred monetary incentive of €864,000 gross, calculated based on the 2015 EBT results approved by the Board of Directors. Furthermore, in 2016 the Deferred Monetary Incentive assigned in 2013 to Claudio Descalzi, as COO of the Exploration & Production Division, vested, resulting in a gross amount paid equaled €659,000.

~~Long-Term Monetary Incentive Plan~~

For the Chief Executive Officer and General Manager, the Board of Directors at its meeting of 15th September 2016, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2016, approved the grant of the 2016 long-term monetary incentive award of 1,350,000 euros gross.

Furthermore, with regard to the Long-Term Monetary Incentive award granted in 2013 to Claudio Descalzi, as COO of the E&P Division, the performance achieved in the reference three-year period did not satisfy the conditions for payment of the incentive.

~~Benefits~~

The Chief Executive Officer and General Manager, in line with the resolution of the Board of Directors Meeting on May 28, 2014, was granted insurance coverage for death or permanent disability, and in compliance with the provisions of the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the supplementary pension plan (FOPDIRE) as well as supplementary health plan (FISDE), together with a company car for business and personal use.

In 2016 Claudio Descalzi, for his role as Chief Executive Officer and General Manager, received a total of €3,120,000 and, for his previous role as COO of the E&P Division (held until May 8, 2014), €659,000 for the long term variable incentives accrued. Consequently, the total amount received was €3,779,000.

~~Managers with strategic responsibilities~~

~~Fixed remuneration~~

For the current Managers with Strategic Responsibilities, within the context of the annual salary review process envisaged for all managers, in 2016 selective adjustments were made to fixed remuneration, in cases of promotion to more senior levels, or in line with necessary market-driven adjustments . The total gross value of the fixed remuneration paid in 2016 to Managers with Strategic Responsibilities is shown in the section “Compensation paid in 2016”, under the item “Fixed compensation”.

~~Annual variable incentive~~

~~In March 2016, annual variable incentives were paid to Managers with Strategic Responsibilities in accordance with the Remuneration Policy and based on performance achieved in 2015.~~

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In particular, the incentive is linked to performance against a range of metrics related to business and sustainability objectives (safety, environmental protection, stakeholder relations), as well as relevant individual, consistent with the provisions of the 2015 Eni Performance Plan.

~~Deferred Monetary Incentive Plan~~

Managers with Strategic Responsibilities were granted 2016 deferred monetary incentive awards, in accordance with the Remuneration Policy and on the basis of the 2015 EBT results approved by the Board of Directors on March 17, 2016, as proposed by the Compensation Committee. In 2016, the Deferred Monetary Incentive award granted in 2013 also vested.

~~Long-Term Monetary Incentive Plan~~

Managers with Strategic Responsibilities were granted their 2016 long-term monetary incentive award, determined in accordance with the Remuneration Policy. With regards to the Long-Term Monetary Incentive awards granted in 2013, the performance achieved in the three-year reference period did not satisfy the conditions for their payment.

~~Severance indemnity for end-of-office or termination of employment~~

During 2016, Managers with Strategic Responsibilities who accepted enhanced voluntary termination offers were paid, in addition to amounts due under legal and contractual obligations, additional amounts defined in line with company policy on early retirement incentives.

~~Benefits~~

For Managers with Strategic Responsibilities, in line with provisions in the national collective bargaining agreement and the supplementary corporate agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (“~~FOPDIRE”) as well as in the supplementary health plan (FISDE), insurance coverage for the risk of death or disability, together with a company car for business and personal use.~~

~~COMPENSATION PAID IN 2016~~

The table below lists the individual remunerations to the Directors, Statutory Auditors, Chief Executive Officer and General Managers and, in aggregate form, to other Managers with strategic responsibilities. The remunerations received from subsidiaries and/or affiliates, except those waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year.

~~In particular:~~

•

based on the criteria of competence, the column “Fixed remuneration” reports the fixed remuneration and fixed salary from employment due for the year, gross of the social security contribution and tax expenses to be paid by the employee; it excludes attendance fees, as these are not provided for. Details of the compensation are provided in the ~~notes, and any indemnities or payments with reference to the employment relationship are indicated separately;~~

•

based on the criteria of competence, the “Remuneration for participation in the Committees” column reports the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately;

•

the column “Variable non-equity remuneration” under the item “Bonuses and other incentives” shows the incentives paid during the year due to rights vested following the assessment and approval of the related performance results by the relevant corporate bodies;

•

~~based on the criteria of competence and taxability, the “Benefits in kind” column reports the value of the fringe benefits awarded;~~

•

~~based on the criteria of competence, the “Other remuneration” column reports any other~~ remuneration ~~deriving from other services provided;~~

•

~~the “Total” column details the sum of the amounts of all the previous items;~~

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•

~~the “Fair value of equity remuneration” column reports the relevant fair value for the year related to the existing stock option Plans, estimated~~report prepared in accordance ~~with international accounting~~to Italian listing standards, which ~~assign~~is incorporated herein by reference.

See the ~~related cost in the vesting period; and~~

•

the “Severance indemnity for end of office or termination of employment” column reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of the financial year in question, or in relation to the end of the mandate and/or employment.

~~Remuneration paid to Directors, Statutory Auditors, Chief Executive officer and General Managers and other Managers with strategic responsibilities~~

~~(€ thousand)~~

Note Position Period for
which the
position
was held
Expiration
of office (*)
Fixed
remuneration Remuneration
for
participation
in the
Committees Variable non-equity
remuneration Benefits
in kind Other
remuneration Total Fair value
of equity
compensation Severance
indemnity
for end of
office or
termination
of employment
First name and Surname Bonuses
and other
incentives Profit
sharing
Board of Directors
Emma Marcegaglia (1) Chairman 01.01-12.31 05.2017 238 (a) 238
Claudio Descalzi (2) Chief Executive Officer
and General Manager 01.01-12.31 05.2017 1,350 (a) 1,755 (b) 15 3,120
Andrea Gemma (3) Director 01.01-12.31 05.2017 80 (a) 90 (b) 170
Pietro Angelo Guindani (4) Director 01.01-12.31 05.2017 80 (a) 50 (b) 130
Karina Litvack (5) Director 01.01-12.31 05.2017 80 (a) 63 (b) 143
Alessandro Lorenzi (6) Director 01.01-12.31 05.2017 80 (a) 80 (b) 160
Diva Moriani (7) Director 01.01-12.31 05.2017 80 (a) 51 (b) 131
Fabrizio Pagani (8) Director 01.01-12.31 05.2017 80 (a) 50 (b) 130
Alessandro Profumo (9) Director 01.01-12.31 05.2017 80 (a) 40 (b) 120
Board of Statutory Auditors
Matteo Caratozzolo (10) Chairman 01.01-12.31 05.2017 80 (a) 97 (b) 177
Paola Camagni (11) Statutory auditor 01.01-12.31 05.2017 70 (a) 80 (b) 150
Alberto Falini (12) Statutory auditor 01.01-12.31 05.2017 70 (a) 80 (b) 150
Marco Lacchini (13) Statutory auditor 01.01-12.31 05.2017 70 (a) 12 (b) 82
Marco Seracini (14) Statutory auditor 01.01-12.31 05.2017 70 (a) 80 (b) 150
Other Managers
with strategic
responsibilities (**)
(15) Remuneration in the company that prepares
the Financial Statements 8,595 9,118 186 126 18,025 4,603
Remuneration from subsidiaries and associates 458 458
Total 9,053 (a) 9,118 (b) 186 (c) 126 (d) 18,483 4,603 (e)
11,561 424 10,873 201 475 23,534 4,603

~~Notes~~

~~(*)~~

~~The term of office expires with the Shareholders’ Meeting approving the Financial Statements for the year ending December 31, 2016.~~

~~(**)~~

Managers who were permanent members of the Company’s Management Committee during the course of the year together with the Chief Executive Officer and Division Chief Operating Officers, or who reported directly to the Chief Executive Officer (twenty-three managers).

~~(1)~~

~~Emma Marcegaglia - Chairman of the board of directors~~

(a) The amount includes the fixed remuneration of €90 thousand set by the Shareholders’ Meeting on May 8, 2014 and the fixed remuneration for the delegated powers of €148 thousand approved by the Board on May 28, 2014.

~~(2)~~

~~Claudio Descalzi - Chief Executive Officer and General Manager~~

(a) The amount includes the fixed remuneration of €550 thousand for the position of Chief Executive Officer, which incorporates the remuneration set by the Shareholders’ Meeting on May 8, 2014 for the position of Director, and the fixed remuneration of €800 thousand for the position of Chief Executive Officer; indemnities due for transfers, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and of the Company’s complementary agreements are added to this amount forExhibit 15. a ~~total of €19 thousand.~~
(b) The amount correspond to the variable annual incentive paid in 2016. To this amount is added the incentives of €659 thousand paid in 2016 for the position of COO of the E&P Division, held until May 8, 2014, related to the deferred monetary incentive assigned in 2013, calculated in relation to the performance targets achieved during the 2013-2015 vesting period.

~~(3)~~

~~Andrea Gemma – Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
(b) The amount includes the €40 thousand for participating in the Control and Risk Committee and €20 thousand for the Sustainability and Scenarios Committee and €30 thousand for the Nomination Committee.

~~(4)~~

~~Pietro Angelo Guindani - Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount includes the €30 thousand for participating in the Compensation Committee and €20 thousand for the Sustainability and Scenarios Committee.~~

~~(5)~~

~~Karina Litvack – Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
(b) The amount includes the €23 thousand for participating in the Control and Risk Committee, €20 thousand for participating in the Compensation Committee and €20 thousand for the Sustainability and Scenarios Committee.

~~(6)~~

~~Alessandro Lorenzi - Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount includes the €60 thousand for participating in the Control and Risk Committee and €20 thousand for the Compensation Committee.~~

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~~(7)~~

~~Diva Moriani – Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount includes the €12 thousand for participating in the Control and Risk Committee, €19 thousand for the Compensation Committee and €20 thousand for the Nomination Committee.~~

~~(8)~~

~~Fabrizio Pagani – Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount includes the €30 thousand for participating in the Sustainability and Scenarios Committee and €20 thousand for the Nomination Committee.~~

~~(9)~~

~~Alessandro Profumo – Director~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount includes the €20 thousand for partecipating in the Sustainability and Scenarios Committee and €20 thousand for the Nomination Committee.~~

~~(10)~~

~~Matteo Caratozzolo - Chairman of the Board of Statutory Auditors~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of TTPC (€32.1 thousand) and of Eni Adfin (€13.9 thousand)~~(i).

~~(11)~~

~~Paola Camagni - Statutory Auditor~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni East Africa (€18 thousand) and Auditor of Syndial (€12 thousand).~~

~~(12)~~

~~Alberto Falini - Statutory Auditor~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni Timor Leste (€12.9 thousand) and Auditor of TTPC (€21.2 thousand).~~

~~(13)~~

~~Marco Lacchini - Statutory Auditor~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
~~(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of SOM (€20.3 thousand) and Auditor of Eni East Africa (€12 thousand).~~

~~(14)~~

~~Marco Seracini - Statutory Auditor~~

~~(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.~~
(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Ing. Luigi Conti Vecchi (€18.2 thousand) and Auditor of Eni Adfin (€9.2 thousand).

~~(15)~~

~~Other Managers with strategic responsibilities~~

(a) The amount of €8,595 thousand for Gross Annual Salary is supplemented by the indemnities owed for the transfers performed, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and with the Company’s additional agreements as well as other indemnities related to the employment contract for a total amount of €851 thousand.
(b) The amount includes the payment of €3,170 thousand relating to the deferred and long-term monetary incentives assigned in 2013 and the pro-rata amounts of the Long-Term Incentive Plans (DMI and LTMI) paid upon consensual employment contract resolution, for the vesting period expired as defined in the respective Plan Regulations.
~~(c) The amount includes the taxable value of insurance and welfare coverage, complementary pensions, the car for business and personal use.~~
(d) Amounts due for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231 and the Manager responsible for the preparation of the Company’s financial statements.
(e) The amount includes the severance indemnity and early retirement incentives paid in relation to the termination of the employment, to which €1,044 thousand is added for the non-competition clauses payable by 2017 at the expiry of the related validity period, subject to the obligations being fulfilled.

~~OTHER INFORMATION~~

~~Accrued compensation~~

Total compensation accrued in the year 2016 pertaining to all the Board members amounted to €7.1 million; it amounted to €0.738 million in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company.

For the year ended December 31, 2016, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2016 period, filled said roles, even if only for a fraction of the year) amounted to €44 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2016. The breakdown is as follow:

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			~~2016~~
			~~(€ million)~~
~~Fees and salaries~~			~~26 ~~
~~Post-employment benefits~~			~~2 ~~
~~Other long-term benefits~~			~~12 ~~
~~Indemnity upon termination of the office~~			~~4 ~~
			~~44 ~~

The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay, as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay.

As of December 31, ~~2016,~~2019, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief ~~Operating~~Executive Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the ~~2016~~2019 period, filled said roles, even if only for a fraction of the year), was ~~€1,706~~€1,427 thousand.

Name		(€ thousand)
Descalzi Claudio ~~Descalzi~~	Chief Executive Officer	~~352~~	371
Senior ~~Managers~~ managers(a)			1,056	~~1,353~~
		~~1,706~~
1,427

(a)

No. ~~18 Managers~~20 managers.

Board practices3

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. Eni complies 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”)~~. On~~, lastly amended on July 9, 2015, the Italian Corporate Governance Committee approved a few amendments to the Corporate Governance Code. At its Meeting held on February 25, 2016, the Board adopted the new recommendations of the Code, acknowledging that Eni’s Corporate Governance model was already broadly compliant with the new recommendations.2018.

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 table above.

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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Board of Directors’ duties and responsibilities

The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated ~~May 9, 2014,~~April 13, 2017, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, in addition to those that cannot be delegated by law, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board.

In the same resolution, the Board of Directors resolved to ~~attribute~~confirm to the Chairman a major role in internal controls and not operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code, the Head of the Internal

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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, the Board of Directors entrusted the Board Secretary with the role of Corporate Governance Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He lends assistance and independent 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.

On ~~May 9, 2014,~~April 13, 2017, the Board reserved to itself the strategic, operational and organizational powers briefly described below:

•

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 ~~Company~~ 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. 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 to the characteristics of the Company 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 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 the key issues that arose during the statutory audit;

•

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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•

examines and approves the annual financial report (which includes Eni’s draft Financial Statements and the Consolidated Financial Statements) and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report;

•

receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers;

•

receives a report from the Board’s internal committees on at least a semi-annual basis;

•

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;

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•

evaluates and approves transactions of the Company and its subsidiaries with related parties provided for in the procedure approved by the Board74, 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;

•

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

•

examines and approves the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting. It also defines the criteria for remunerating the senior executives of the Company and of the Group and takes steps to implement 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 the Company.

Directors’ independence

On the basis of statements made by the Directors and other information available to the Company, during its meeting of ~~May 9, 2014~~April 13, 2017 and, after an investigation by the Nomination Committee, lastly at its meeting of February ~~17, 2015,~~27, 2020, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and ~~Zingales~~8Trombone satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and ~~Zingales~~Trombone have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code. Chairman Marcegaglia, in compliance with the Corporate Governance Code, could not be deemed independent as she is a significant representative of the Company.5

~~On July 29, 2015,~~At the ~~Eni~~last assessment, the Board of Directors ~~appointed Alessandro Profumo~~also evaluated that the commercial relationships between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative, and between Eni and companies of the KME Group, companies subject to ~~replace Luigi Zingales, who resigned on July 2, 2015. The Board~~significant influence, also indirectly, by Director Moriani, are not significant for the purpose of assessing the independence of these Directors, ~~following an investigation performed by the Nomination Committee, on the basis of declarations made by Profumo and information available~~having regard to the ~~Company, ascertained that Profumo was independent according to law~~nature and the ~~Corporate Governance Code. With reference to the marital relationship~~amounts of Profumo with an employee of the Company, the Board resolved that this relationship does not compromise the independence requirements requested by the Corporate Governance Code, on account of Profumo’s ethical and professional integrity and his international reputation and taking into account the fact that his spouse is employed at a foundation, which is independent of Eni SpA9.

~~On February 25, 2016, and most recently on February 28, 2017,~~these relationships. The relationships were evaluated on the basis of statements made by the Directors and other information available to the Company, ~~after an investigation by~~and taking into account that – due to the ~~Nomination Committee,~~nature of the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Profumo satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Morianicompanies mentioned above – transactions between these

~~(7)~~4

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.~~2012 and, lastly, on April 4, 2017.

~~(8)~~5

~~Luigi Zingales resigned from~~Although the Chairman of the Board of Directors ~~on July 2, 2015.~~

~~(9)~~

~~On May 26, 2016,~~is a non-executive Director, the ~~Board~~Code treats her as a significant representative of ~~Directors, after an investigation by the Nomination Committee, on the basis of declarations made by Profumo and information available to~~ the Company ~~verified that Profumo - confirmed by the Shareholders’ Meeting on May 12, 2016 - was independent in accordance with law and~~(Application Criterion 3.C.2 of the Corporate Governance ~~Code, confirming the previous assessments.~~Code).

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companies and ~~Profumo have been deemed independent by the Board pursuant~~Eni were subject to related parties’ transactions regulation and reported to the ~~criteria and parameters recommended by the Corporate Governance Code.~~Company’s body. The ~~Board confirmed the independence requirements of Director Profumo on the basis of the aforementioned reasons. At the last assessment, the~~ Board of Directors also ~~evaluated that the commercial relationships between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative, are not significant for the purpose of assessing~~confirmed the independence of Director Lorenzi, who the next May 5, 2020 will complete the ninth year of office as Director, ~~himself, having regard to the nature and the amounts of these relationships.~~taking into account that his office as Director will expire on May 13, 2020.

The Board of Statutory Auditors ~~ascertained that~~always verified the proper application of criteria and procedures adopted by the Board of Directors ~~correctly applied the assessment criteria and procedures for evaluating~~in assessing the independence of its members.

The independence criteria may be not be 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 ~~Compensation~~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. 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.

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

All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. In addition, the Chairmen of the Committees report to the Board at each meeting of the Board on the key issues examined by the Committees in their previous meetings.

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

The Chairman of the Board of Statutory Auditors or a Statutory Auditor designated by him, 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 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 ~~Compensation~~Remuneration Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their ~~remuneration.~~remuneration6.

The Board Secretary and Corporate Governance Counsel coordinates the secretaries of the Board Committees, receiving at this end 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, ~~Compensation~~Remuneration Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on ~~May 9, 2014, except for~~April 13, 2017.

Remuneration Committee

Members: Andrea Gemma (Chairman), Pietro A. Guindani, Alessandro Lorenzi, Diva Moriani.

Rules of the Remuneration Committee establish that “no Director ~~Profumo, appointed by~~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 as a member of Nomination Committee and~~Directors.”

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Sustainability and Scenarios Committee on September 17, 2015, and Director Diva Moriani, who was appointed as a member of the Control and Risk Committee on September 15, 2016, replacing Director Karina Litvack10~~; Director Diva Moriani left the Compensation Committee on December 22, 2016.~~

~~Compensation Committee~~

~~Members: Pietro A. Guindani (Chairman), Karina Litvack, Alessandro Lorenzi~~11.

The ~~Compensation~~Remuneration Committee is made up of non-executive, independent Directors. All the members possess adequate professional requirements and expertise for carrying out the duties assigned to the Committee. ~~In particular,~~The Committee’s rules require that at ~~his appointment, the Director Guindani was identified~~least one of its members possess adequate knowledge and experience of financial matters or remuneration policies, as assessed by the Board asat the ~~member with “adequate knowledge and experience in finance~~time of his or ~~remuneration policies” as recommended by the Corporate Governance Code.~~her appointment.

Established by the Board of Directors for the first time in 1996, in accordance with the By-laws, the Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee:

submits ~~to the Board of Directors for its approval~~ the Remuneration Report and in particular the Remuneration Policy for Directors and Managers with strategic responsibilities to ~~be presented~~the Board of Directors for approval, prior to its presentation at the Shareholders’ Meeting called to approve the year’s financial statements, ~~as provided for~~in accordance with the time limits set by applicable law;

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

presents proposals for the remuneration of the Chairman ~~of the Board~~ and the Chief Executive Officer, ~~covering~~including the various ~~forms~~components of compensation and ~~benefits awarded; c)~~ non monetary benefits;

presents proposals for the remuneration of ~~members of~~Board Committee members;

having examined the ~~Board’s internal committees; d) examines the CEO’s indications and presents proposals for: (i)~~Chief Executive Officer’s indication, proposes general criteria for the compensation of Managers with strategic ~~responsibilities; (ii)~~responsibilities, the annual and ~~long-term~~Long-Term incentive plans, including equity-based ~~plans;~~ones, sets performance objectives and ~~(iii) establishing~~assesses performance ~~targets and assessing results for performance plans~~against them, in connection with the determination of the variable portion of the ~~compensation~~remuneration for Directors with delegated powers and with the implementation of the approved incentive plans; e)

monitors ~~the~~ execution of Board resolutions regarding remuneration matters; f) periodically evaluates the adequacy, overall consistency and actual implementation of the adopted policy, as described in letter a) above, formulating proposals on the topic for the Board of Directors; g) performs the tasks required under the Company’s procedures for handling related party transactions; h) through the Chairman of the Committee, informs the Board of Directors on the main issues examineddecisions taken by the ~~Committee thereof during~~Board;

reports at the first available meeting of the ~~Board; furthermore,~~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 ~~once~~ every six months and no later than the ~~deadline~~time limit for the approval of the ~~annual Financial Statements~~Annual Report and the ~~semi-annual financial report, on its activities~~Interim Report at June 30, at the Board ~~Meeting indicated~~meeting designated by the Chairman of the Board of ~~Directors;~~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 may access the information and i)Company functions necessary to perform its duties and can avail itself of external advisors who are not in positions that might compromise their independence of judgement, within the terms and budget limits established by the Board of Directors.

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

During ~~2016,~~2019, the ~~Compensation~~Remuneration Committee met ~~a total of nine~~ten times, with an average attendance of ~~94,4%~~100% of its members and an average duration of 32 hours and 1310 minutes. ~~All the Committee meetings were attended by at~~At least one member of the Board of Statutory Auditors participated in each meeting, whit constant participation of the Chairman of the Board of Statutory Auditors. At the invitation of the Chairman of the Committee, Company executives and external advisors also took part in specific meetings, to provide information and clarifications requested by the Committee.

Earlier in the year, the Committee focused its activities in particular on the following topics: ~~(i)~~

the periodic ~~assessment~~evaluation of ~~the~~ Remuneration Policy implemented in ~~2015, also~~2018 in order to prepare the proposed policy guidelines for 2019, providing for keeping the structure and criteria of remuneration of the Directors and Executives with strategic responsibilities defined in 2017 for the entire term, as regards in particular the simplified variable incentive system, as discussed in greater detail in the 2017 Remuneration Report;

ii.

the review of the Company’s 2018 results for the purpose of ~~defining~~implementing the ~~proposed Policy Guidelines for 2016; (ii) review of 2015 corporate performance linked to the implementation of annual~~Short- and ~~long-term~~Long-Term variable incentive plans, ~~in accordance with~~using a ~~“variation~~predetermined gap analysis ~~methodology”~~method approved by the Committee in order to neutralize the positive or negative impact of exogenous factors ~~to allow an unbiased~~and enable the objective assessment of the performance ~~levels~~ achieved; ~~(iii)~~

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iii.

the definition of ~~the 2016~~2019 performance targets ~~related~~relevant to the variable incentive ~~plans, with~~ plans;

iv.

the ~~introduction of a new metric in the Annual Incentive Plan, enhancing exploration resources as a fundamental asset in order to preserve the sustainability~~finalization of the ~~Company’s future results; (iv) definition of the proposals~~proposal for the implementation of the ~~Deferred Monetary Incentive Plan~~annual variable incentive system for the Chief Executive Officer and General ~~Manager as well other senior executives; (v)~~Manager;

the review of the ~~2016~~2019 Eni Remuneration ~~report; (vi) ) review~~Report;

vi.

the examination of the outcome of the ~~first cycle~~engagement activities held with leading institutional investors and proxy advisors in view of ~~engagement conducted with main institutional investors,~~the general meeting, in order to maximize shareholder consensus on the ~~2016~~2019 Remuneration ~~Policy,~~Policy; the Chairman of the Committee also took part in the aforementioned meetings, bearing witness to the importance given by the Committee to dialogue with shareholders;

vii.

risk assessment and scenario analysis, examination of the composition of shareholders, including the retail segment, as well as examination of voting recommendations issued by leading proxy advisors and of related voting projections, ~~produced~~which were performed with the support of ~~an international consultant.~~a leading consulting firm;

~~(10)~~viii.

~~On July 28, 2016, Eni’s Board~~the start of ~~Directors approved the replacement~~a further extensive dialogue with a broad range of ~~Director Karina Litvack with another Director - identified by the Board itself in Director Diva Moriani on September 15, 2016 -~~investors in the ~~Control~~run-up to the annual meeting, with a view to promoting participation and ~~Risk Committee (CRC) in light of~~support for the ongoing investigations related to alleged conspiracy against the Company, reported also by the press. The board has taken this decision only to safeguard the Company from the risks of possible conflicts of interest until the closing of the investigation, remaining the presumption that Director Litvack has not been involved in the facts under investigations.Eni Remuneration Policy.

~~(11)~~

~~Director Diva Moriani left the Compensation Committee on December 22, 2016~~

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In the second ~~part~~half of the year, the Committee ~~primarily analyzed~~examined the 2019 Shareholders’ Meeting vote results, with regard to the Eni Remuneration Report, compared to the results of the ~~2016 Shareholder’s Meeting season, regarding the Eni Remuneration Report, the main~~major Italian and European listed companies ~~as well as companies in~~and of the ~~peer group of reference. Among other main~~Eni’s Peer Group.

As regards further relevant activities carried out, the ~~Committee also: (i) finalised~~Committee:

finalized the proposal ~~concerning~~(2019 grant) for the ~~fulfilment (2016 award)~~implementation of the 2017-2019 Long Term Share Incentive ~~Plan~~Plane for the Chief Executive Officer and General Manager and ~~other critical~~for key management personnel; ~~(ii) initiated~~

finalized the ~~examination~~proposal on the exercise of the ~~2017 Remuneration Policy Guidelines, developing in particular, over~~option to activate the ~~course of a number of meetings, a proposal for the revision of the variable incentive system applicable to~~non-compete agreement entered into with the Chief Executive Officer and General Manager, as ~~well as Managers with Strategic Responsibilities, with~~set out in the ~~goal~~2019 Remuneration Report;

iii

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

examined the updating of ~~further strengthening~~remuneration benchmark studies and started to review the ~~alignment between~~proposals for Remuneration Policy Guidelines for the ~~action of management and shareholder interests; (iii) approved~~2020-2023 term;

examined the ~~annual~~general criteria for defining the 2020 engagement plan ~~prepared~~ by ~~the competent company functions~~conducting a preliminary analysis and ~~was informed~~segmentation of the ~~findings~~institutional investors that attended the 2019 Shareholders’ Meeting;

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 of the Shareholders’ Meeting on the Remuneration policy described in the first ~~cycle of meetings held with the main proxy advisors, in implementation~~section of the ~~engagement plan for 2017.~~Remuneration Report, and an advisory vote on the second section, concerning remuneration paid during the reporting period.

The ~~composition and appointment,~~Committee scheduled four meetings for the first four months of 2020, three of which had already been held as ~~well as the duties and operating procedures,~~ of the ~~Committee are governed by the rules approved by the Board~~date of ~~Directors on July 30, 2014, and most recently amended on September 15, 2016, available to the public on the Company’s website.~~approval of this Report.

Control and Risk Committee

Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Karina Litvack and Diva ~~Moriani~~12.Moriani.

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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 Directors137 who possess the necessary expertise consistent with the duties they are required to perform148.

In particular, at their appointment, the Directors Lorenzi, Litvack and Moriani 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 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, on 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 report on the main issues arising during the audit.

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

~~(12)~~

On September 15, 2016, Eni’s Board of Directors appointed Diva Moriani as member of the Control and Risk Committee in place of Director Karina Litvack, following the replacement approved by the Board of Directors on July 28, 2016.

~~(13)~~

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.

~~(14)~~

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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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~~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

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oversees 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 to the Board on proposals by the Chairman in agreement with the CEO concerning the appointment, 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.

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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 ~~which~~ 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, ~~have received a notice of investigation~~ for 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 ~~July 30, 2014 and amended on April 7, 2016,~~May 9, 2017 available to the public at the Company’s website.

Nomination Committee

Members: Diva Moriani (Chairman), Andrea Gemma, ~~(Chairman), Diva Moriani,~~ Fabrizio Pagani and ~~Alessandro Profumo.~~Domenico Livio Trombone.

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

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The Committee provides recommendations and advice to the Board of ~~Directors with recommendations and advice. In particular,~~Directors. More specifically, the Committee:

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

provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment ~~fall~~falls under the ~~Boards’~~Board’s responsibility and oversees the associated succession plans. Where possible and appropriate, ~~in relation~~and with due regard to the shareholding structure, the Committee proposes the CEO succession plan to the Board of ~~Directors the succession plan for the Chief Executive Officer;~~ Directors;

acting upon a proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession ~~plan~~planning for the Company’s ~~key management personnel;~~ managers with strategic responsibilities;

proposes candidates to serve as Directors onto 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 onregarding the minimum number of independent Directors and of the percentage reserved for the less represented gender;

proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, taking account of any ~~recommendation~~recommendations received from shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders;

oversees the annual self-assessment program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and deals with the preliminary activity for appointing an external consultant for such ~~self assessment.~~self-assessment. On the basis of the results of the self-assessment, the Committee provides its opinions to the Board of Directors regarding the size and composition of the Board or its Committees, as well as, the skills and managerial and professional qualifications it feels should be represented within the same Board and Committees so that the Board itself can give its opinion to the shareholders prior to the appointment of the new Board;

proposes to the Board of Directors the slate of candidates for the position of Director to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3, first ~~sentence,~~period, of the By-laws;

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

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

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

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 ~~financial statements~~ and ~~of the~~ semi-annual financial report, on the activity carried out as well as on the adequacy of the appointment system, at the Board ~~Meeting~~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 ~~July 30, 2014, and amended on April 7, 2016,~~May 9, 2017, available to the public at the Company’s website.

Sustainability and Scenarios Committee

Members: Pietro A. Guindani (Chairman), Karina Litvack, Fabrizio Pagani and Domenico Trombone.

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~~Sustainability and Scenarios Committee~~

~~Members: Fabrizio Pagani (Chairman), Andrea Gemma, Pietro A. Guindani, Karina Litvack and Alessandro Profumo.~~

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: ~~the~~ health, well-being and safety of people and communities; respect and the protection of rights, particularly of the human rights; local development; access to energy, energy sustainability and climate change; ~~the~~ environment and efficient use of resources; integrity and transparency; and innovation.

Board of Statutory Auditors

The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of ~~May 8, 2014~~April 13, 2017 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, ~~2016.~~2019.

Name	Position	Year first appointed to Board of Statutory Auditors
~~Matteo Caratozzolo~~Rosalba Casiraghi	Chairman	~~2014~~2017
Enrico Maria Bignami	Auditor	2017
Paola Camagni	Auditor	2014
~~Alberto Falini~~Andrea Parolini	Auditor	~~2014~~
~~Marco Lacchini~~	~~Auditor~~	~~2014~~2017
Marco Seracini	Auditor	2014
Stefania Bettoni	Alternate	2014
~~Mauro Lonardo~~Claudia Mezzabotta	Alternate	~~2014~~2017

Paola Camagni, ~~Alberto Falini,~~Andrea Parolini, Marco Seracini and Stefania Bettoni (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; ~~Matteo Caratozzolo~~Rosalba Casiraghi (Chairman), ~~Marco Lacchini~~Enrico Maria Bignami and ~~Mauro Lonardo~~Claudia Mezzabotta (Alternate) were candidates listed in the slate presented by non-controlling ~~shareholders (institutional investors).~~shareholders.

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, ~~which were applied for the first time in the elections of the Board of Directors and the Board of~~two Statutory Auditors ~~at the Shareholders’ Meeting held on May 8, 2014, one Statutory Auditor and one Alternate Statutory Auditor~~ were ~~drawn from the less represented gender. For the next two elections, one third of the statutory auditors will be~~ drawn from the less represented gender.

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

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

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within the scope of the Board’s Authority, the adequacy of the internal control system and the

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administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.

In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, ~~(in force as of December 31, 2016)~~ in its role as the “internal control and financial auditing committee” the Board of Statutory ~~Auditors~~Auditors: a) informs the Board of Directors of the conclusion of the statutory audit and transmits to the Board the “additional report” of the audit firm adding proper evaluation if deemed necessary; b) oversees ~~the following: (a)~~ the financial reporting ~~process; (b)~~process and presents recommendations to ensure its integrity; c) controls the ~~efficacy~~effectiveness of internal quality control system and Risk Management, the effectiveness of internal audit, ~~(where applicable)~~with reference to the financial reporting process, without violating its independence; d) oversees the statutory audit of annual accounts and ~~risk management systems; (c) the auditing~~consolidated accounts, also considering results of quality control of the ~~annual~~audit activity performed by the public authority responsible for regulating the Italian financial ~~statements~~markets; e) verifies and ~~Consolidated Financial Statements; and (d)~~monitors the independence of the ~~external auditor or~~audit Firm with particular reference to non-audit services; f) is responsible of the ~~Audit~~procedure to select the audit Firm, ~~in particular with regard~~making a recommendation to the ~~provision~~Shareholders’ Meeting for the appointment of ~~non-audit services to~~ the ~~entity subject to financial auditing.~~audit Firm.

The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee” are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “U.S. Sarbanes-Oxley Act” (discussed in greater detail below).

As already set forth in the Consolidated Law on Financial Intermediation and currently regulated by Article 13 of Legislative Decree No. 39/2010, the Board of Statutory Auditors submits a reasoned opinion to the Shareholders’ Meeting on the selection of the external auditors and the determination of the associated fees.

~~As from 2017 the above tasks provided for by the Legislative Decree. no. 39/2010, have been updated by Legislative Decree no. 135/ 2016, to comply with European Directive no 56/2014.~~

In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements.

On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, ~~and lastly on May 28, 2014,~~ the Board of Statutory Auditors approved the internal rules, later updated, concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s ~~website~~15.website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC ~~rules are as follows:~~include:

•

evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor;

•

overseeing the work of the external Auditor engaged to audit the accounts or perform other audit, review or certification services;

•

examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;

•

making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial ~~reporting;~~reporting.

In addition the Board of statutory auditor:

•

~~approving~~approves the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;

•

~~approving the procedures for the pre-approval of specifically identified admissible non-audit services and examining the disclosures on the execution of the authorized services;~~

•

~~evaluating requests to use the external auditor firm engaged to perform audit services for admissible non-audit services and providing its opinion to the Board of Directors;~~

•

~~examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within~~

~~(15)~~

~~These internal rules will be subject to revision and possible updating to take into account the aforementioned regulatory changes.~~

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generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;

•

~~examining~~examines reports from the CEO and the CFO ~~concerning~~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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Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and

•

~~examining reports from the CEO and the CFO concerning~~ ii) any fraud that involves management or other employees who have a significant role in the Company’s internal controls.

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

Eni Watch Structure and Model 231

In accordance with the Italian regulations concerning the “administrative liability of legal entities deriving from criminal offences”, contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, “Legislative Decree No. 231/2001”), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the Watch Structure. Moreover, as a result of changes in the Italian legislation governing the matter and of the Company’s organizational structures, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of ~~October 27, 2016, ratified~~September 19, 2019 approved the updating of Model ~~231~~231.

During 2019, in accordance with Eni Watch Structure, Eni has conducted a project to ~~incorporate a number of legislative changes in~~revise and transform the ~~environmental crimes provided for by Law no. 68/2015 (“eco-crimes”).~~

~~The synergies between the~~existing Code of Ethics, ~~– an integral part and essential general principle~~whose very “procedural” nature was justified by the different internal regulatory context existing at the time of its first adoption, into a modern charter of values.

The Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics; the new Code sets out the fundamental principles of Eni’s Model 231 ~~– and Model 231 are highlighted by the assignment, to the Eni Watch Structure,~~which is one of the ~~function~~pillars of ~~Guarantor of the Code of Ethics.~~ Eni “regulatory system” and inspires it.

At present, the Watch Structure of Eni is composed of three external members, including the Chairman, and four internal members. The internal members are Company executives in charge of Legal Affairs, labor law matters and disputes, Internal Audit and Integrated Compliance. External members are independent professionals, experts in law and/or economic matters. Also in order to grant the Watch Structure the greatest extent of autonomy and independence, the set of rules adopted by the Watch Structure provide for specific quorum to convene and to pass resolutions so to ensure that all resolutions are effectively adopted with the favourable vote of the majority of the external members.

Audit Firm

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

In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm ~~issue~~issues a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit Firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting.

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For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit Firm. Moreover, Eni’s Audit Firm, for the purpose of issuing an opinion on the Consolidated Financial Statements, assumes responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which, taken together, account for an immaterial share of consolidated assets and revenues.

Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of ~~April 29, 2010 appointed Ernst & Young~~May 10, 2018 approved the engagement of PricewaterhouseCoopers SpA to perform the external statutory audit of the accounts of Eni SpA and the audit of the internal control system over financial reporting, pursuant to US law, for the ~~financial years 2010-2018.~~period 2019 – 2027.

Court of Auditors (Corte dei conti)

The financial management of Eni is subject to the control of the Court of Auditors in order to preserve the integrity of the public finances. This task ishas 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.~~ 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 on 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, the Board of Statutory Auditors and the Control and Risk Committee.

Employees

As of December 31, ~~2016,~~2019, Eni had a total of ~~33,536~~32,053 employees, with an increase of 352 employees, up by 1.1% compared to December 31, 2018, which mainly reflects an increase of 486 employees working in Italy and a decrease of ~~660 employees, or down by 1.9% from December 31, 2015, which mainly reflects a decrease of 690~~134 employees working ~~outside Italy.~~abroad.

The increase of personnel headcount in Italy is mainly due to the execution of the turn-over plan for guaranteeing a structure consistent with the objectives of starting up new businesses, rebalancing the business portfolio and enhancing the opportunities offered by new technologies.

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

Employees at year end

2014 (1)

2015 (1)
2016
(number)
Exploration & Production 12,777 12,821 12,494
Gas & Power 4,561 4,484 4,261
Refining & Marketing and Chemicals 11,884 10,995 10,858
Corporate and Other activities 5,624 5,896 5,922
34,846 34,196 33,536

~~(1)~~

~~Excluding the operating segment E&C divested in January 2016.~~

	2019		2018		2017
	(number)
Exploration & Production		11,502		11,645		11,970
Gas & Power		3,015		3,040		4,313
Refining & Marketing and Chemicals		11,291		11,136		10,916
Corporate and Other activities		6,245		5,880		5,735
		32,053		31,701		32,934

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The table below sets forth Eni’s employees as of December 31, ~~2014, 2015~~2017, 2018 and ~~2016~~2019 in Italy and outside Italy:

2014 (1)

2015 (1)
2016
(number)
Exploration & Production Italy 4,534 4,572 4,608
Outside Italy 8,243 8,249 7,886
12,777 12,821 12,494
Gas & Power Italy 2,067 2,023 2,032
Outside Italy 2,494 2,461 2,229
4,561 4,484 4,261
Refining & Marketing and Chemicals Italy 9,286 8,635 8,577
Outside Italy 2,598 2,360 2,281
11,884 10,995 10,858
Corporate and other activities Italy 5,320 5,650 5,693
Outside Italy 304 246 229
5,624 5,896 5,922
Total Italy 21,207 20,880 20,910
Outside Italy 13,639 13,316 12,626
34,846 34,196 33,536
of which senior managers 1,074 1,061 1,036

~~(1)~~

~~Excluding the operating segment E&C divested in January 2016.~~



		2019		2018		2017
		(number)
Exploration & Production	Italy		4,556		4,531		4,510
	Outside Italy		6,946		7,114		7,460
			11,502		11,645		11,970
Gas & Power	Italy		2,040		2,089		2,282
	Outside Italy		975		951		2,031
			3,015		3,040		4,313
Refining & Marketing and Chemicals	Italy		8,901		8,740		8,580
	Outside Italy		2,390		2,396		2,336
			11,291		11,136		10,916
Corporate and other activities	Italy		5,991		5,642		5,501
	Outside Italy		254		238		234
			6,245		5,880		5,735
Total	Italy		21,488		21,002		20,873
	Outside Italy		10,565		10,699		12,061
			32,053		31,701		32,934
of which senior managers			1,031		1,016		1,012

We seek to maintain constructive relationship with labor unions.

Share ownership

As of February 28, ~~2017,~~2020, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was ~~303,091~~269,178 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; 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		~~87,447~~87,010(1)
Claudio Descalzi	CEO		~~39,455~~68,755(2)
Board of
Statutory Auditors			~~5,000~~ ~~(2)~~none
Senior Managers			~~171,189~~142,713(3)

(1)

Of which No. ~~1,034~~597 shares held under Asset Management, No. 7,143 shares held under Asset Management jointly ~~with~~ a third person, and No. 45,000 shares held ~~as naked owner~~in bare ownership jointly with a third person.

(2)

~~Shares held under Asset Management.~~Updated as of March 19, 2020.

(3)

Of which No. ~~14,390~~6,890 shares owned by ~~spouses~~wives 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, ~~2017,~~2020, the total amount of Eni’s voting securities owned, ~~by these shareholders 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

~~The following table shows the percentage of Eni’s share capital owned,~~ either directly or indirectly, by persons that ~~as of February 28, 2017~~ have notified that their holding ~~either~~ exceeds the threshold of 3% ~~since March 18, 2016~~1 pursuant to Article 120 of the Legislative Decree No. 58/1998 ~~(as amended by article 1 of Legislative Decree No. 25 of February 15, 2016)~~ and to the Consob Regulation No. 11971/1999 ~~(as amended by Consob Resolution No. 19614~~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

As of ~~May 26, 2016) or~~February 28, 2020, the ~~previous threshold~~percentage of ~~2% (in effect until March 17, 2016)~~Eni’s treasury shares was equal to 1.70% of the share capital12.

~~Title of class~~	~~Percent of class~~
~~People’s Bank of China~~		~~2.102~~

~~Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified~~In relation to the Italian legislation governing the special powers of the Italian State ~~to comply with European rules. See~~see “Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)”.

As of ~~February 28, 2017,~~March 10, 2020, there were ~~36,611,569~~33,623,608 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately ~~2.0%~~1.9% of Eni’s share capital. See “Item 9 – The offer and the listing”.

Related ~~party~~parties transactions

In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with ~~non-consolidated subsidiaries and~~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 Eni Group companies.

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 47~~Note 36 of the Notes on Consolidated Financial Statements”.

(1)

~~The Legislative Decree No. 25/2016, in force since March 18, 2016, modified the~~Major holdings pursuant to Article 120 of the Legislative Decree No. 58/1998 ~~increasing this holding threshold from 2%~~are updated also on the basis of communication made by intermediaries pursuant to ~~3%. See “Item 10 – Additional information – Shareholder ownership thresholds”.~~Article 83-novies of the Legislative Decree No. 58/1998 in order to exercise the corporate rights.

(2)

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

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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 to 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 to the Consolidated Financial Statements and that in some instances a negative outcome is not probable or it is not possible to make a reliable estimates of contingency losses, Eni believes that ~~the foregoing~~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 38~~Note 27 of the Notes on Consolidated Financial Statements”.

Dividends

~~Eni’s future~~Management is committed to a progressive shareholders’ remuneration policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. For the year 2020 management is planning to distribute a full-year dividend of €0.89 per share, up by approximately 3.5% vs. 2019. The Company’s dividend policy ~~as well as~~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 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 ~~“Risk factors” set out in Item 3 and the~~ oil price ~~scenario~~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 2017, we confirm our commitment to pay a full cash dividend of €0.80 per share and, later on, to a progressive distribution policy in line with the achievement of our plans of underlying earnings and cash flow growth and the scenario evolution. For further information on the Company’s dividend policy see “Item 5 – Management’s Expectations of Operation.”

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” ~~and the other planning assumptions and initiatives described in “Item 5 – Management’s expectations of operations”~~.

At the General Shareholders’ Meeting scheduled on ~~April~~May 13, ~~2017,~~2020, management intends to propose the distribution of a dividend of ~~€0.80~~€0.86 per share for fiscal year ~~2016,~~2019, of which ~~€0.40~~€0.43 already paid as interim dividend in September ~~2016.~~2019.

Total cash outlay for the ~~2016 balance~~2019 final dividend is expected at approximately ~~€1.4~~€1.5 billion to be paid in 2020 (whereas ~~€1.4~~€1.5 billion were distributed in September ~~2016)~~2019) if the General Shareholders’ Meeting approves the annual dividend.

Significant changes

See “Item 5 – Recent ~~developments”~~developments and Management’s expectations of operations” for a discussion of significant ~~events~~subsequent business developments and transactions occurred after ~~2016 year end~~the closing date up to the latest practicable date.

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Item 9. THE OFFER AND THE LISTING

Offer and listing details

The principal trading market for the ordinary shares of Eni SpA (Eni), without indication of par value (the “Shares”), is the Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (Borsa Italiana). Eni’s American Depositary Receipts (ADRs), each representing two Shares, are listed on the New York Stock Exchange.

The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. See “Item 3 – Key information – Exchange rates” regarding applicable exchange rates during the periods indicated below.

MTA New York
Stock Exchange
High Low High Low
(Euro per share) (U.S.$ per ADR)
Year ended December 31,
2012 18.700 15.250 49.440 36.850
2013 19.480 15.290 52.120 40.390
2014 20.410 13.290 55.300 32.810
2015 17.430 13.140 39.290 29.280
2016 15.470 10.930 33.330 25.000
2015
First quarter 16.680 13.370 37.690 31.960
Second quarter 17.430 15.720 39.290 34.940
Third quarter 16.210 13.140 35.610 30.300
Fourth quarter 15.730 13.240 36.020 29.280
2016
First quarter 13.800 10.930 31.050 25.000
Second quarter 14.580 12.320 33.330 28.170
Third quarter 14.900 12.310 33.250 27.650
Fourth quarter 15.470 12.260 32.240 26.260
Month of
September 2016 14.030 12.310 31.600 27.650
October 2016 13.770 12.890 30.170 28.940
November 2016 13.140 12.260 28.740 26.260
December 2016 15.470 13.540 32.240 28.650
January 2017 15.720 14.210 33.260 30.880
February 2017 14.580 14.120 31.260 30.070
March 2017 (through March 17, 2017) 15.270 14.470 32.250 30.780

Since ~~January 18, 2012, the Bank of New York Mellon~~June 27, 2017, Citibank N.A. (the “Depositary”) functions as the company’s depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) among Eni, the Depositary and the beneficial owners (“Beneficial Owners”) and registered holders from time to time of the ADRs issued hereunder.

As of ~~February 28, 2017,~~March 10, 2020, there were ~~36,611,569~~33,623,608 ADRs outstanding, representing ~~71,233,138~~67,247,216 ordinary shares or approximately 2%1.9% of all Eni’s shares outstanding, held by ~~105~~92 holders of record (including the Depository Trust Company) in the United States, ~~104~~91 of which are U.S. residents. Since certain of such ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or ~~elsewhere.~~

~~The~~elsewhere.The Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian Stock Exchange. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on

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MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The constituents of the FTSE MIB are selected based on market capitalization of free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free float and foreign ownership limits. ~~Since June 1, 2009, the~~ FTSE MIB is the principal indicator used to track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are ~~the first largest~~a component of the FTSE MIB, with a weighting of approximately ~~14%~~9,4%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective December ~~19, 2016.~~23, 2019.

~~Beginning from October 6, 2014, a~~A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the ~~Italian Securitized Derivatives Market~~multilateral trading facility of securitised derivatives financial instruments, organised and managed by Borsa Italiana (SeDeX). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic ~~regulated market~~multilateral trading facility where it is possible to trade securitized derivatives (for instance, covered warrants and certificates).

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an “official price”, calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades, and ~~block trades, and~~ a “reference price”, calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective February ~~13, 2017:~~3, 2020: (i) ± 5.0% (or such other amount established by Borsa Italiana in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price ~~shall be~~being the previous day’s reference price, in the opening auction or the price at which contracts are concluded in the auction phase after each auction phase; if no auction price is determined, the static price is equal to the price of the first contract concluded in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the “Guide to the Parameters”) with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.

Markets

Consob is the public authority responsible for regulating and supervising the Italian securities 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, regulated markets in Italy; it is responsible for the organization and management of the Italian Stock Exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading and the surveillance of the markets.

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According to Consob regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which, inter alia, are MTA ~~(shares,~~(for example, shares, convertible bonds, pre-emptive rights, ~~warrants and Funds)~~warrants), ETFplus ~~(Exchange~~(for example, Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes, Structured ETFs and ~~open-ended funds market)~~Actively managed ETFs), IDEM ~~(index, stock~~(futures and ~~other derivatives market), SeDeX (covered warrants and certificates)~~options contracts whose underlying assets are financial instruments, interest rates, foreign currencies, goods or related indexes), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets.

According to EUthe regulatory framework introduced by Markets in Financial Instruments Directive ~~(No. 2004/39/EC) (MiFID)~~No. 2014/65/EU as amended (“MiFID II”), as implemented in Italy, and Regulation (EU) No. 600/2014 (“MiFIR”), applicable from January 3, 2018, and Consob regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (MTFs) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm ~~or a bank~~ which, on an organized, frequent systematic and substantial basis, deals on own account bywhen executing client orders outside a Regulated Market, an MTF or an Organized Trading Facility (“OTF”) without operating a ~~MTF. Outside Regulated Markets, block trading is also permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana.~~

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multilateral system. Following the transposition in Italy of ~~Directive No. 2014/65/EU (“~~MiFID ~~II”), which is due to be implemented by 3 January 2018, Organized Trading Facilities (“OTFs”) will be~~II and the application of MiFIR, OTFs are now included among the “trading venues” that are subject to regulation.

An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract. The implementation of the MiFID II and entry into force of the Regulation (EU) No. 600/2014 (“MiFIR”) will entail some additional changes to the regulatory framework currently applicable to Regulated Markets, MTFs and Systematic Internalisers.

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

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

The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it).

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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 (last amended on November 20, 2014).~~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. See “Exhibit 1”.

Company objects and purpose

In accordance with Article 4 of Eni’s By-laws, the Company 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.

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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”1 (“MSG”), which has been in effect from January 1, 20112 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

~~(1)~~

~~The Board of Directors modified this Management System Guideline on January 19, 2012.~~

~~(2)~~

This MSG replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The new provisions regarding information to be provided to the public, under both the Consob Regulation and the MSG, have been applied since December 1, 2010.

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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 ~~explain~~state their potential interests related to Eni and its ~~subsidiaries, and in~~subsidiaries. In any case ~~they inform~~ the ~~CEO (or~~Directors and the ~~Chairman,~~Statutory Auditors report in good time the ~~case the CEO holds an interest) about individual~~single transactions that Eni intends to carry out in which they have an ~~interest;~~interest. Directors report the ~~CEO~~interest to the Chief Executive officer (or ~~Chairman)~~the Chairman, in the case of interests of the Chief Executive Officer), who will ~~then inform~~in turn notify the other Directors and the Board of Statutory Auditors. Statutory Auditors report the interest to the other Statutory Auditors and the Chairman of the Eni SpA Board of Directors.

Compensation

Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors ~~assigned particular duties~~with delegated powers in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the ~~Compensation~~Remuneration Committee, after ~~consultation with~~examining the opinion of the Board of Statutory Auditors (for more details about the compensation policy in ~~2016,~~2019, see ~~“Item 6 – Compensation”)~~the Remuneration Report 2020 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 €4,005,358,876.003, 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)

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

(2)

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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Eni’s shares (the “Shares”) must be held with “Monte Titoli SpA” (the Italian Central Securities Depository) and their beneficial owners may exercise their rights through special deposit accounts opened with intermediaries, such as banks, brokers and securities dealers.

Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the Meeting, by electronic means.

Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.

In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors.

Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE.

Dividend rights

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

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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 ~~25, 2017,~~30, 2020, 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 on a single slate only.

There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.

Liquidation rights

In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors.

Change in shareholders’ rights

A shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision making quorum established by law for extraordinary meetings.

Shareholders’ Meeting

The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in “ordinary” or “extraordinary” form. The ordinary and the extraordinary Shareholders’ Meetings are normally held after a single call, with the majorities required by law in this case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after more than one call; their resolutions at first, second or third call must be passed with the majorities required by law in each case.

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Shareholders’ Meetings shall normally be held at the Company’s registered office, unless otherwise decided by the Board of Directors, provided however they are held in Italy.

The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by mail (the information is also available on the Company’s website) and, if envisaged, it may include instructions for participating in the Shareholders’ Meeting by means of telecommunication systems, as well as exercising the right to vote by electronic means. The Board of Directors shall make a report on each of the items on the agenda available to the public at the Company’s registered office, on the Company’s website and by other means envisaged by Consob regulations by the same date of the publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements.

The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the

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Shareholders’ Meeting. Credit and debit records entered on the authorized intermediaries’ accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement, issued by the authorized intermediary, must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the Meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the Meeting; otherwise, the date of each call is deemed the reference date.

Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the Meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collection of proxies shall be made available in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.

The right to vote may also be exercised by mail in accordance with the applicable laws and regulations. If provided for in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules.

The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by applicable laws and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.

The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.

The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his or her opinion on the items on the agenda.

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During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information.

Stock ownership limitation and voting rights restrictions

There are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to both residents and non-residents of Italy).

In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 334 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.

~~(3)~~

This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below.

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Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban.

Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.

Limitation on changes in control of the Company (Special Powers of the Italian State)

Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012 (Law No. 56/2012), lastly amended by Decree Law No. 105 of September 21, 2019 ratified with amendments by Law No. 133 of November 18, 2019, modified Italian legislation governing the special powers of the Italian State to comply with European rules45.

The ~~new~~ special powers ~~no longer~~ apply ~~to specific State-controlled companies, identified by name, but~~ to companies that hold strategic assets vital to the interests of the Italian State as defined by the ~~ministerial~~ regulations which implement the relevant law.

The current legislation governing the special powers briefly include: a) veto power (or the power of imposing conditions or requirements) over certain transactions involving strategic assets that could result in a situation, not regulated by Italian or EU laws, that threatens serious injury to interests regarding networks and systems security, as well as continuity of supply; and b) power of attaching conditions or opposing the acquisition by an entity outside of the EU of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets, when such an acquisition may result in a threat of serious injury to the above mentioned essential interests of the Italian State. The shareholding of third parties who have entered into a shareholders’ agreement with the buyer is taken into account in the calculation of above mentioned relevant shareholdings.

With particular reference to the power referred to in letter b), 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 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)

(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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The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of the EU of stock of company that holds strategic assets be allowed on condition of reciprocity, in compliance with international agreements signed by Italy or the EU.

These powers are exercised exclusively on the basis of objective and non-discriminatory criteria.

Decree Law No. 148 of October 16, 2017, ratified with amendments by Law No. 172 of December 4, 2017, extended the special powers of the Italian State to high-technology industries. Decree Law No. 105 of September 21, 2019 ratified with amendments by Law No. 133 of November 18, 2019 replaced high-technology industries with sectors provided under Article 4, paragraph 1 of EU Regulation 452/2019. Furthermore, with regard to investments in companies with strategic assets by a non-EU investor, the decree defined the assessment criteria to determine whether a foreign investment could affect security or public order.

Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.

In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily

~~(4)~~

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controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any of such provisions.

Shareholder ownership thresholds

There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Finance56 and the Consob Regulation67, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%78 ~~(until March 17, 2016, the threshold was 2%)~~, 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6% and 90% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds.

Such disclosures shall be made – using the forms contained in Annex 4A to the above Regulation – without delay and, in any case, within four days of the transaction, starting from the day on which the subject gains knowledge of the transaction that can lead to the obligation, regardless of the date of execution, or from the date on which the subject obliged to make the disclosure gains knowledge of the event that leads to changes in the share capital as contemplated in the Consob Regulation.

For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria89. 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 investments910.

Under the above mentioned 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. 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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integration or revocation of the issuer’s administrative or control bodies. Consob can identify, with its own regulation, the cases where the aforementioned declaration is not due, taking into account the characteristics of the entity making the declaration or of the company whose shares have been purchased.

The declaration shall be transmitted to the company whose shares have been purchased and to Consob and shall be subject to public disclosure in accordance with the terms and conditions established by Consob Regulation.

Voting rights attached to listed shares which have not been notified pursuant to the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in court, under the Italian Civil Code.

According to the Italian Civil Code (Article ~~2359-bis~~)2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed one-fifth of the capital of the parent company – if the latter is a listed company – taking into account for this purpose the shares held by the same parent company or its subsidiaries.

The Consolidated Law on Finance provides rules governing cross-holdings. In particular, except for the cases contemplated by the above mentioned Article ~~2359-bis~~2359-bis of the Italian Civil Code, in case of a reciprocal participation exceeding the limit of 3% ~~(until March 17, 2016, the threshold was 2%)~~ of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

~~(5)~~

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

~~(6)~~

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

~~(7)~~

The Legislative Decree No. 25/2016, in force since March 18, 2016, modified the Article 120 of the Legislative Decree No. 58/1998, increasing this holding threshold from 2% to 3%. 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.

~~(8)~~

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

~~(9)~~

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

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The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-~~quater~~.1w-quater.1 of the Consolidated Law on Finance) if the threshold is exceeded by both companies subsequent to an agreement authorized in advance by the ordinary shareholders’ meetings of the companies concerned.

If a person holds an interest exceeding the aforementioned threshold of a listed company, such listed company or any person controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended. Where it is not possible to ascertain which of the two persons was the last to exceed the limit, the suspension shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

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~~)(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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Finally, ~~in accordance with~~pursuant to Law No. 287 of October 10, 1990, any merger or acquisition of (legal or factual) sole or joint control over a company or any change of control over a company ~~that~~is subject to the prior authorization by the Italian Antitrust Authority11 if the companies involved exceed given turnover thresholds. If the said merger, acquisition or change of control would create or strengthen a dominant position in the ~~domestic~~Italian market in a manner that eliminates or significantly reduces competition, ~~is prohibited and mergers and acquisition~~the Italian Antitrust Authority can either prohibit the transaction or make it subject to remedies preventing a restriction of ~~specified dimension must~~competition. Moreover, if the transaction or the companies involved exceed other thresholds set by European or other countries’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value or market shares of the parties), the transaction can also be subject to the prior authorization by competition authorities of ~~the Italian Antitrust Authority~~10. However, if the merging parties or the acquiring party and the company to be acquired operate in more than one EU Member State and/or outside Europe and exceed certain thresholds (e.g. turnover, asset value or market share thresholds), the antitrust approval for the merger and/or acquisition can fall under the jurisdiction of the European Commission or the EU Members States and/or other ~~Competition Authorities outside Europe.~~jurisdictions.

Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than are required by law.

Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.

Material contracts

None.

~~(10)~~

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

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Exchange controls

~~There are~~Under current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls ~~in Italy. Residents and non-residents in Italy may carry out any investments, divestments and other transactions~~do require, however, that ~~entail a~~an accredited intermediary must handle all payments or transfer of ~~assets~~funds made by an Italian resident to or from Italy, subject only to the reporting, record-keeping and disclosure requirements described below. In particular, residents of Italy may hold foreign currency and foreign securities of any kind, within and outside Italy, while non-residents may invest in Italian securities without restriction and may export from Italy cash, instruments of credit or payment and securities, whether in foreign currency or euro, representing interest, dividends, other asset distributions and the proceeds of dispositions.

Updated reporting and record-keeping requirements are contained in the Italian legislation which implements an EU directive regarding the free movement of capital. Such legislation requires that transfers into or out of Italy of cash or securities in excess of €12,500 be reported in writing to the relevant authority (Ministry of Economy and Finance) by residents or non-residents that effect such transfers directly, or by banks, securities dealers or Poste Italiane SpA (Italian Mail) that effect such transactions on their behalf. In addition, banks, securities dealers or Poste Italiane SpA effecting such transactions on behalf of residents or non-residents of Italy are required to maintain records of such transactions for five years. These records may be inspected at any time by Italian Tax and Judicial Authorities.

Non-compliance with these reporting and record-keeping requirements may result in administrative fines or, in the case of false reporting and in certain cases of incomplete reporting, criminal penalties.a non-resident.

Taxation

The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.

Italian taxation

The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.

Income tax

Dividends regarding income of financial year 2019 to be paid in 2020, received by Italian resident individuals, holding the shares or ADRs in ~~relation to interest exceeding 2% of the voting rights or 5% of the share capital (“substantial interest”)~~connection with entrepreneurial activity, are included in the taxable income subject to personal income tax to the extent of ~~49.72%~~58.14% of their amount. Article 1, paragraph 64 of Law No. 208 of December 28, 2015 (“Italian Budget Law for the 2016”) provides that the percentages of the dividends relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61 of the aforementioned Italian Budget Law for the 2016.PersonalPersonal 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 ~~relation to non-substantial interest not related to the conduct of a business~~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. If the non-substantial interest is related to the conduct of a business, dividends are included in the taxable business income for 49.72% of their amount. Article 1, paragraph 64 of the Italian Budget Law for the 2016 provides that the percentages of the dividends and capital gains relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61 of the aforementioned Italian Budget Law for the 2016. The change of tax rate does not apply to the entities referred to into Article 5 of Presidential Decree 22 December 1986 No. 917.

~~Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to undistributed profit of 2007 and previous years.~~

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)~~ (“SICAV”) are not subject to ~~substitute~~

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substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares.

Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units.

Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute ~~tax (12.5% as regards income from government bonds).~~tax.

Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment.

Dividends are subject to a ~~1.375%~~1,20% substitute tax introduced by the Financial Bill for 2008 where the conditions in Article 27, paragraph 3-~~ter~~,3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to companies and entities subject to a corporate income tax in a European Union Member State or in ~~Norway. Because corporate tax rate has been decreased to 24%, from~~ the 1st ~~of January 2017, the above mentioned dividends on 2017 income are subject to a 1,2% withholding tax.~~European Economic Area.

The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income Tax Treaties with approximately 90 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.

In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes.

Under the Tax Treaty between the United States and Italy (the “Italy U.S. Tax Treaty”), dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the ~~IRS)~~“IRS”) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.

Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.

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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)~~(“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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until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith.

Capital gains tax

This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy.

Profits gained by Italian resident individuals, ~~upon the sale of a substantial interest~~not in connection with entrepreneurial activity, in financial year 2019, are ~~included in the taxable base~~ subject to ~~personal income~~substitute tax for 49.72% of their amount. Article 1, paragraph 64 of the Italian Budget Law for the 2016 provides that the percentages of the capital gains relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61, of the aforementioned Italian Budget Law for the 2016. Gains realized upon the sale of non-substantial interest is subject to a substitute tax at a 26% ~~rate.~~.

For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return:

•

the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and

•

the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 26% substitute tax to be applied by the portfolio.

Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.

On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to the capital gains tax.

However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non taxability pursuant to the convention have been satisfied.

Financial Transactions Tax

Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable is 0.10% for ADR negotiated in regulated markets (like the NYSE).

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Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law.

Inheritance and gift tax

Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:

(a)

4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary);

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(b)

6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding €100,000 (per beneficiary);

(c)

6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity, as well as to persons related by collateral affinity up to the third degree; and

(d)

8 per cent: in all other cases.

If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.

United States taxation

The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not ~~purport to address~~discuss all material tax consequences of the ownership of Shares or ~~ADSs.~~ADSs, including tax consequences arising under the Medicare contribution tax on net investment income. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of the combined voting power of Eni SpA’s ~~Shares,~~voting stock or of the total value of Eni SpA’s stock, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar.

This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, (the “Code”), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.

If an entity or arrangement that is treated as a partnership for U.S. federal income tax purposes holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs.

As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.

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 ~~income tax convention between the United States and~~ Italy U.S. Tax Treaty with their advisors and to discuss with their advisors any

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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.

~~Dividends~~Distributions

Subject to the passive foreign investment company ~~(PFIC),~~(“PFIC”) rules discussed below, distributions paid on the shares 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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or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities.

For non-corporate U.S. Holders, dividends ~~paid~~ that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by Eni SpA that are received with respect to the ~~Group~~ADSs will generally be qualified dividend income if the ADSs are readily tradable on an established securities market in the United States. Eni SpA’s ADSs are listed on the New York Stock Exchange and Eni SpA therefore expects that dividends with respect to the ADSs will be qualified dividend income. Dividends paid by Eni SpA with respect to the Shares ~~or ADSs~~ will generally be qualified as dividend ~~income.~~ income provided that, in the year that you receive the dividend, Eni SpA is eligible for the benefits of the Italy U.S. Tax Treaty. Eni SpA believes that it is currently eligible for the benefits of the Italy U.S. Tax Treaty and Eni SpA therefore expects that dividends on the Shares and ADSs will be qualified dividend income, but there can be no assurance that Eni SpA will continue to be eligible for the benefits of the Italy U.S. Tax Treaty.

The amount of the dividend distribution that must be included in the income of a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot EUR/USD rate on the date the dividend distribution is includible in such person’s income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the U.S. Holder includes the dividend payment in income to the date he or she converts the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a reduction or refund of the tax withheld is available to a U.S. Holder under Italian law or under the income tax convention between the United States and Italy, the amount of tax withheld that could have been reduced or that is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See “Italian taxation – Income tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the ~~shares~~ADSs or Shares will generally be income from sources outside the United States and will, ~~depending on your circumstances,~~generally be ~~either~~ “passive” ~~or “general”~~ income for purposes of computing the foreign tax credit allowable to you. However, if (a) Eni SpA is 50% or more owned, by vote or value, by United States persons and (b) at least 10% of Eni SpA’s earnings and profits are attributable to sources within the United States, then for foreign tax credit purposes, a portion of Eni SpA’s dividends would be treated as derived from sources within the United States. With respect to any dividend paid for any taxable year, the United States source ratio of Eni SpA’s dividends for foreign tax credit purposes would be equal to the portion of Eni SpA’s earnings and profits from sources within the United States for such taxable year, divided by the total amount of our earnings and profits for such taxable year. Eni SpA does not expect to be 50% or more owned, by vote or value, by United States persons, and therefore does not expect that any portion of Eni SpA’s dividends will be treated as derived from sources within the United States.

Sale or exchange of ~~shares~~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, determined at~~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 ~~spot rate on~~payment of the ~~date of disposition).~~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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PFIC rules

Eni SpA believes that Shares and ADSs should not currently be treated as stock of a PFIC for U.S. federal income tax purposes ~~but~~and Eni SpA does not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, ~~unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs,~~ gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, ~~if classified as~~unless a U.S. Holder

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~~one~~ elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, the U.S. Holder would be treated as having realized such gains and certain “excess distributions” ratably over the holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, a U.S. Holder’s Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during the period the Shares or ADSs were held. Dividends received from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to the U.S. Holders either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.

Documents on display

Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at: ~~http:~~https://www.eni.com/~~en_IT/documentation/documentation.page?type=bil-rap.~~en-IT/publications.html.

The Company is subject to the information requirements of the U.S. Security Exchange Act of 1934 applicable to foreign private issuers.

In accordance with these requirements, Eni files its Annual Report on Form 20-F and other related documents with the U.S. SEC. It’s possible to read and copy documents that have been filed with the U.S. via commercial document retrieval services, and from the SEC ~~at the U.S. SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, USA.~~website (www.sec.gov).

~~You may also call the U.S. SEC at +1 800-SEC-0330 or log on to www.sec.gov.~~

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~~It is also possible to read and copy documents referred to in this Annual Report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17~~th ~~floor, New York, USA.~~

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Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the possibility that the exposure to fluctuations in commodity prices, currency exchange rates, interest rates or ~~commodity prices~~other market benchmarks will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.

The impact of changes in crude oil prices on the Company’s ~~downstream gas and~~ refining and marketing ~~businesses~~ and petrochemical ~~operations~~businesses depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated ~~products as in the case of gas prices.~~products. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.

As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives.

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

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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 Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA, Eni Finance International and Eni Finance ~~International~~USA manage the Group subsidiaries’ financing requirements in ~~and~~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 commodity risk of each business unit (Eni’s business lines or subsidiaries) is pooled and managed by the parent company Midstream business department, with Eni Trading & Shipping executing the negotiation of commodity derivatives.

During 2013, the above mentioned centralized model for the execution of financial derivatives has been ring fenced in light of the relevant new financial regulations which became effective (EMIR/Dodd ~~Frank)~~Frank act). Eni’s activities are in compliance with regulatory requirements for execution of financial derivatives 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. ~~Activities~~Company’s activities in financial derivatives 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 can be qualified a 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 ~~direct or caused by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk,~~ of different assets under Eni control or that Eni will have under its controls in the normal course of ~~business;~~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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Use of financial derivatives (in euro or currencies different from euro) is allowed with the following risk reducing purposes:

•

Back to ~~back:~~back: includes market risk-free instruments that are negotiated in accordance to an execution criteria and normally settled with an intermediation fee. They normally comply with hedge accounting requirements or own use exemption. These are transaction-based activities characterized by a substantial absence of market risk. A hedging instrument can be considered back to back when the financial derivative is structured as to match as much as possible asset class, size and maturity of the hedged position. As a result, the combination of the hedged item, normally a single asset/contract or an order received by mean of an internal derivative, and the hedging instrument, i.e. the financial derivative, is substantially market risk free or is exposed only to a basic risk related to the ineffective portion of the hedging item. In addition, the hedging item may ~~entailcounterparty~~entail counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes.

•

Flow hedging: flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, in accordance to a portfolio basis. A central department processes a continuous flow of orders from the Group various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity 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.

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•

Asset-backed hedging: is a portfolio-based activity performed to protect 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 ~~is an~~the asset, the higher is its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. ~~In order to~~To protect 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 ~~term~~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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portfolio in line with company’s targets. Market risk associated to portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence, financial ~~Derivatives~~derivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several ~~times.~~times in a given time frame. These derivatives may lead to gains, as well as losses which in each case may be significant and are accounted through profit as they lack the hedge requirements provided by IFRS.

Pursuant to internal policy, all derivatives transactions concerning interest rates and foreign currencies are executed for risk reducing purposes, as described above. Only commodity derivatives can also be executed in the context of non-risk reducing operations and be consequently classified as Proprietary Trading, which is an ancillary activity not related to industrial assets that makes use of financial derivatives which are entered into with the objective to obtain an uncertain profit, if favorable market expectations occur.

Eni monitors on a daily basis that every activity involving derivatives is correctly classified according to the risk reducing taxonomy (i.e. back to back, flow hedging, asset-backed hedging or portfolio management), is directly or indirectly related to the hedged industrial assets and effectively optimizes the risk profile to which Eni is, or could be, exposed. When some derivatives fail to prove their risk reducing purpose, they are reclassified as Proprietary Trading. Provided that Proprietary Trading is segregated ex ante from other activities, its resulting market risk exposure is subject to specific limits expressed in terms of Stop Loss, VaR and ~~notional.~~notional amounts. The aggregated notional amounts of ~~non risk~~non-risk reducing derivatives at Group level are constantly benchmarked with the thresholds required by relevant international financial regulations.

Please refer to “Item 18 – ~~note 38~~Note 27 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks. ~~Please also refer to “Item 18 – notes 15, 23, 28, 33 and 34 of the Notes on Consolidated Financial Statements” for details of the different derivatives owned by the Company in these markets.~~

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Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Item 12A. Debt securities

Not applicable.

Item 12B. Warrants and rights

Not applicable.

Item 12C. Other securities

Not applicable.

Item 12D. American Depositary Shares

In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. ~~Since January 18, 2012, Eni’s ADRs are issued, cancelled and exchanged at the office of Bank of New York Mellon, as depositary (the “Depositary”) under~~

Pursuant to the Deposit Agreement dated June 27, 2017 (the “Deposit Agreement”) between Eni, ~~the Depositary~~Citibank N.A. and the holders ~~of ADRs.~~and beneficial owners ADSs, Citibank N.A. serves as the Depositary for Eni’s ADR Program, and Citibank N.A. Milan Branch serves as Custodian.

Computershare is the transfer agent for the Eni SpA ADR program.

Société Générale Securities Services SpA and UniCredit SpA are the custodians (the “Custodian”) on behalf of the holders of Eni’s ADRs, and their principal offices are located in Milan, Italy.

Fees and charges ~~paid~~payable by ADR holders

~~The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for~~Pursuant to the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable propertyDeposit Agreement, ADR holders may be required to pay various fees to the ~~fees.~~Depositary, and the Depositary may refuse to provide any service for which a fee is assessed until the applicable fee has been paid.

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The ~~table below sets forth all~~following ADS fees ~~and charges that a holder~~are payable under the terms of ~~Eni’s ADRs may have to pay, either directly or indirectly, to Bank of New York Mellon, as Depositary.~~the Deposit Agreement:

~~Type of service~~Service	~~Amount of fees or charges(1)~~ Rate	~~Depositary actions~~By Whom Paid
~~(a)~~(1) ~~Depositing~~Issuance of ADSs (e.g., an issuance upon a deposit of Shares, upon a change in the ADS(s)-to-Share(s) ratio, or ~~substituting the underlying shares~~for any other reason), excluding issuances as a result of distributions described in paragraph (4) below.	~~$5.00~~Up to U.S. $5.00 per 100 ADSs (or ~~less) for each 100 ADSs~~ ~~(or portion of 100 ADSs)~~fraction thereof) issued.	~~Each person to whom ADRs are issued against deposits of shares, including deposits and issuances in respect of:~~ • ~~Share distributions, stock split, rights, merger.~~ • ~~Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities.~~ Person receiving ADSs.
~~(b)~~(2) ~~Selling~~Cancellation of ADSs (e.g., a cancellation of ADSs for delivery of deposited Shares, upon a change in the ADS(s)-to-Share(s) ratio, or ~~exercising rights~~for any other reason).	~~$5.00~~Up to U.S. $5.00 per 100 ADSs (or ~~less) for each 100 ADSs~~ ~~(or portion of 100 ADSs)~~fraction thereof) cancelled.	~~Distribution or sale of securities, the fee~~Person whose ADSs are being ~~in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities.~~cancelled.
~~(c)~~(3) ~~Withdrawing an underlying security~~Distribution of cash dividends or other cash distributions (e.g., upon a sale of rights and other entitlements).	~~$5.00~~Up to U.S. $5.00 per 100 ADSs (or ~~less) for each 100 ADSs~~ ~~(or portion of 100 ADSs)~~fraction thereof) held.	~~Acceptance of ADRs surrendered for withdrawal of deposited securities.~~Person to whom the distribution is made.
~~(d)~~(4) ~~Transferring, splitting~~Distribution of ADSs pursuant to (i) stock dividends or ~~grouping receipts~~other free stock distributions, or (ii) an exercise of rights to purchase additional ADSs.	~~Registration or transfer fees~~Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held.	~~Transfers, combining or grouping of depositary receipts.~~Person to whom the distribution is made.
~~(e)~~(5) ~~Expenses~~Distribution of ~~the depositary~~securities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares).	~~Varied charges~~Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held.	~~Expenses incurred on behalf of holders in connection with:~~ • ~~The Depositary’s or its custodian’s compliance with applicable law, rule or regulation.~~ • ~~Stock transfer or other taxes and other governmental charges.~~ • ~~Cable, telex, facsimile transmission/delivery.~~ • ~~Expenses of~~Person to whom the ~~Depositary in connection with the conversion of foreign currency into U.S. dollars (which are paid out of such foreign currency).~~ • ~~Any other charge payable by Depositary or its agents.~~ distribution is made.
~~(f)~~(6) ~~Distribution of cash~~ADS Services.	~~$0.02~~Up to U.S. $5.00 per 100 ADSs (or ~~less) per ADS~~fraction thereof) held on the applicable record date(s) established by the Depositary.	~~Any cash distribution to ADS registered holders.~~Person holding ADSs on the applicable record date(s) established by the Depositary.
~~(g)~~ ~~Depositary services~~	~~$0.02 (or less) per ADS~~ ~~per calendar year~~	~~Depositary services.~~

~~(1)~~

~~All fees~~Direct and ~~charges are paid by ADR holders to Bank of New York Mellon as Depositary and Transfer agent.~~

~~Fees and~~indirect payments ~~made~~ by the Depositary ~~to the issuer~~

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 ~~2016, as agreed in the Deposit Agreement with the previous depositary bank, JPMorgan Chase Bank of New York, and subsequent amendments,~~2019, the Depositary will reimburse to Eni up to ~~US$2,200,000~~$1,800,000 in connection with the above mentioned expenditures.

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~~Expenses waived or paid directly to third parties by the Depositary~~

The Depositary ~~reimbursed~~has also agreed to waive certain standard fees associated with the ~~company, or paid amounts on~~administration of the ~~company’s behalf to third parties, or waived its fees and expenses, of US$189,419.31 for the year ended December 31, 2016.~~

~~Category of expense reimbursed, waived or paid directly to third parties~~	~~Amount reimbursed,~~ ~~waived or paid directly to~~ ~~third parties for the year~~ ~~ended December 31, 2016~~
	~~(US$)~~
~~BNY Mellon products and services~~		~~120,000.00~~
~~BNY Mellon related to servicing registered shareholders~~		~~650.90~~
~~BNY Mellon paid to third-party vendors(1)~~		~~68,768.41~~
~~Total~~		~~189,419.31~~

ADR Program.

~~(1)~~

~~Includes payments for AGM and related ADR Program services.~~

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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 Financial Officer, 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 Financial Officer, 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 Financial Officer 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 Financial Officer, 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, ~~2016.~~2019.

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The effectiveness of the Company’s internal control over financial reporting as of December 31, ~~2016,~~2019, has been audited by ~~Reconta Ernst & Young~~PricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F.

Changes in Internal Control over Financial Reporting

There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 16. [RESERVED]

Item 16A. Board of Statutory Auditors financial expert

Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: ~~Matteo Caratozzolo,~~Rosalba Casiraghi, who is the Chairman of the Board, Enrico Maria Bignami, Paola Camagni, ~~Alberto Falini, Marco Lacchini~~Andrea Parolini and Marco Seracini. All members are independent.

Item 16B. Code of Ethics

Eni adopted a Code of Ethics that applies to all Eni’s employees, including ~~Eni’s Chief Executive Officer, Chief~~Chiefs, Officers, principal Financial ~~Officer~~ and ~~Chief~~ Accounting ~~Officer.~~Officers, Directors and Statutory Auditors. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section ~~Corporate~~ Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F.

Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model.

Item 16C. Principal accountant fees and services

~~Reconta Ernst & Young~~PwC SpA has served as Eni principal independent public auditor for fiscal ~~years 2016 and 2015~~year 2019 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.

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

The following table shows total fees ~~paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures~~ for services ~~provided~~rendered to Eni by ~~Eni to~~ its public auditors ~~Reconta Ernst & Young~~PwC SpA and its member firms of PwC Network for the year ended December 31, 2019. The amount shown for the year ended December 31, 2018 have been paid to EY SpA and its respective member firms ~~for~~which has served as Eni principal independent public auditor since the ~~years ended December 31, 2016 and 2015, respectively:~~fiscal year 2018.

	Year ended December 31,				Year ended December 31,
	2015		2016		2019		2018
	(€ thousand)				(€ thousand)
Audit fees		33,752		21,433		15,748		25,445
Audit-related fees		1,138		1,874
Audit -related fees						1,045		1,628
Tax fees		3
All other fees
Total		34,893		23,307		16,793		27,073

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, ~~and consultancy services rendered in connection with acquisition deals,~~ 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 ~~within the Eni Group which are either controlled or jointly~~ controlled (directly or indirectly) by Eni ~~SpA.~~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 ~~2016,~~2019, 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)~~(C) of Rule 2-01 of Regulation S-X.

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Item 16D. Exemptions from the Listing Standards for Audit Committees

Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, performs the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act to be carried out by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 – Board of Statutory Auditors” above).

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

The ~~issuer and its affiliated purchasers have not executed any purchase~~Eni Board of ~~equity securities~~Directors, in execution of the ~~issuer since~~authorization granted by the ~~end~~Eni Shareholders’ Meeting of ~~2014~~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 €400,000,000 and up to a maximum of 67,000,000 shares. The purchases started in the first week of June 2019 and asended in the month of ~~the date of the 20-F filing for the year ended~~ December ~~31, 2016.~~2019.

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

~~Not applicable.~~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.

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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Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual

Corporate ~~Governance.~~Governance. Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities. The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code for Italian listed companies, which Eni has adopted (hereinafter the Corporate Governance Code).

Independent Directors

NYSE ~~standards.~~standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a Director’s independence.

Eni ~~standards.~~standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of ~~their~~

judgment.

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~~judgment.~~ Eni’s By-laws require that at least one Director – if the Board has no more than five members – or at least three Directors – if the Board is composed of more than five members – must satisfy the independence requirements. The Corporate Governance Code provides for additional independence requirements, recommending that the Board of Directors includes an adequate number of independent non-executive Directors. In particular, for issuers belonging to FTSE-MIB index of the Italian Stock Market, like Eni, the Corporate Governance Code recommends that at least one-third of the members of the Board of Directors shall be independent Directors. In any event, independent Directors shall not be fewer than two. 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.~~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.~~standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year without the other Directors. During ~~2016,~~2019, Eni’s independent Directors had ~~numerous~~ opportunities to meet, ~~formally and~~ informally, to hold discussions and exchange opinions.

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Audit Committee

NYSE standards. Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

Eni ~~standards.~~standards. At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on regulated U.S. markets, assigned to the Board of Statutory Auditors, effective from June 1, 2005 and within the limits set by Italian law, the functions specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the U.S. SEC rules (see “Item 6 – Board of Statutory Auditors” earlier). Under Section 303A.07 of the NYSE Listed Company Manual, audit committees of U.S. companies have additional functions and duties which are not mandatory for non-U.S. private issuers and which are therefore not included in the list of functions reported in “Item 6 – Board of Statutory Auditors”.

Nominating/Corporate Governance Committee

NYSE ~~standards.~~standards. U.S. listed companies must have a Nominating/Corporate Governance Committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers.

Eni ~~standards.~~standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a nomination committee the majority of whose members shall be independent Directors. The Nomination Committee of Eni is made up of three to four Directors, a majority of whom shall be independent in accordance with the recommendations of the Corporate Governance ~~Code~~1.Code. On

~~(1)~~

~~The Committee is currently made up of four Directors, three of whom are independent.~~

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~~May 9, 2014,~~ April 13, 2017, the Board of Directors of Eni established the Nomination Committee, chaired by ~~Andrea Gemma~~Diva Moriani (independent Director) and composed of ~~Diva Moriani~~Andrea Gemma (independent Director), Fabrizio Pagani (non-executive Director) and ~~Luigi Zingales~~Domenico Livio Trombone (independent Director). ~~On September 17, 2015, the Board appointed Director Alessandro Profumo (independent Director) as a member of the Committee, replacing Luigi Zingales who resigned from the Board on July 2, 2015.~~ Further details on this Committee are reported in the Item 6.

~~Compensation~~Remuneration Committee

NYSE ~~standards.~~standards. U.S. listed companies must have a ~~Compensation~~Remuneration Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The ~~Compensation~~Remuneration Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The ~~Compensation~~Remuneration Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers.

Eni standards.Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a ~~Compensation~~Remuneration Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have an adequate understanding of and experience in financial matters or compensation policies. First established by the Board of Directors in 1996, the ~~Compensation~~Remuneration Committee is currently chaired by Director ~~Pietro A. Guindani.~~Andrea Gemma. The other members include directors ~~Karina A. Litvack~~Pietro Guindani, Alessandro Lorenzi and ~~Alessandro Lorenzi~~2Diva Moriani. 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). 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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Eni ~~standards.~~standards. At its Meetings of December 15, 2003 and January 28, 2004, the Board of Directors of Eni approved an organizational, management and control model pursuant to Italian Legislative Decree ~~No. 231~~No.231 of 2001 (hereinafter “Model 231”) and established the associated Eni Watch Structure. Moreover, after subsequent approvals of the updates to Model 231 in response to changes in the Italian legislation governing the matter and in the Company organizational structures, on March 14, 2008, the Board of Directors approved the overall revision of Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of Eni’s Code of Conduct of 1998. Most recently, the Board of Directors, in its meeting held on ~~October 27, 2016, ratified~~September 19, 2019, approved the updating of Model 231, ~~to incorporate a number~~as defined by the CEO with the support of ~~legislative changes provided for by law No. 68/2015 (“eco-crime”). The CEO is supported in this activity by~~ the “Technical Committee 231”, consisting of members from the Company’s Legal Affairs, Integrated Compliance Department, Human Resources and Organization and Internal Audit units.

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

Eni’s Code of Ethics sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All Eni personnel, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under U.S. SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties. The synergies between the Code of Ethics and Model 231 are underscored by the designation of the Eni Watch Structure, established under Model 231, as the Guarantor of the Code of Ethics. The Guarantor of the Code of Ethics acts to ensure the protection and promotion of the above principles. Every six months, it presents a report on the implementation of the Code to the Control and Risk Committee, to the Board of Statutory Auditors and to the Chairman and

~~(2)~~

~~Director Diva Moriani left the Compensation Committee on December 22, 2016.~~

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~~the CEO, who in turn reports on this to the Board of Directors.~~ At present, the Watch Structure of Eni SpA is composed of three external members, including the Chairman, and four internal members. The internal members are Company executives in charge of Legal Affairs, labor law matters and disputes, Internal Audit and Integrated Compliance. External members are independent professionals, experts in law and/or economic matters. Also in order to grant the Watch Structure the greatest extent of autonomy and independence, the set of rules adopted by the Watch Structure provide for specific quorum to convene and to pass resolutions so to ensure that all resolutions are effectively adopted with the favorable vote of the majority of the external members.

Item 16H. Mine safety disclosure

Not applicable since Eni does not engage in mining operations.

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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, ~~2016~~2019 and December 31, ~~2015~~2018 and January 1, ~~2015~~2018		~~F-3~~F-5
Consolidated profit and loss account for the years ended December 31, ~~2016, 2015~~2019, 2018 and ~~2014~~2017		~~F-4~~F-6
Consolidated Statements of comprehensive income for the years ended December 31, ~~2016, 2015~~2019, 2018 and ~~2014~~2017		~~F-5~~F-7
Consolidated Statements of changes in ~~shareholder~~s’shareholders’ equity for the years ended December 31, ~~2016,~~2019, ~~2015~~2018 and ~~2014~~2017		~~F-6~~F-8
Consolidated Statement of cash flows for the years ended December 31, ~~2016, 2015~~2019, 2018 and ~~2014~~2017		~~F-8~~F-11
Notes on Consolidated Financial Statements		~~F-10~~F-13

Item 19. EXHIBITS

	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.			Description of securities registered under Section 12 of the Exchange Act
	8.			List of subsidiaries (see Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements)
	11.			Code of Ethics
	Certifications:
	12.1.			Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
	12.2.			Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
	13.1.			Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
	13.2.			Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
	15.a(i)			Excerpt of the pages and sections of the remuneration report prepared in accordance to Italian listing standards for the year 2019 incorporated herein by reference
	15.a(ii)			Report of DeGolyer and MacNaughton
	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

~~1. By-laws of Eni SpA~~

~~8. List of subsidiaries~~

~~11. Code of Ethics~~

~~Certifications:~~

~~12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act~~
~~12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act~~

13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)

13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)

~~15.a(i) Report of DeGolyer and MacNaughton~~
~~15.a(ii) Report of Ryder Scott Co~~
~~15.a(iii) Gaffney, Cline & Associates~~

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~~Report of Independent Registered Public Accounting Firm~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Eni ~~S.p.A.~~SpA

OPINIONS ON THE FINANCIAL STATEMENTS AND INTERNAL CONTROL OVER FINANCIAL REPORTING

We have audited the accompanying consolidated balance ~~sheets~~sheet of Eni ~~S.p.A.~~SpA and its subsidiaries (the “Company”) as of December 31, ~~2016 and 2015,~~2019, and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in ~~shareholders'~~shareholders’ equity and cash flows for ~~each~~the year then ended, 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, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

~~We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)~~Treadway Commission (COSO). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the ~~consolidated~~ financial position of ~~Eni S.p.A. at~~the Company as of December 31, ~~2016~~2019, and ~~2015, and~~ the ~~consolidated~~ results of its operations and its cash flows for ~~each of~~ the ~~three years in the period~~year then ended ~~December 31, 2016,~~ in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

~~As discussed~~ Also in ~~Note 5 to the consolidated financial statements,~~our opinion, the Company ~~has elected to change its method of accounting for the oil & gas exploration and production activities to the “Successful Efforts Method”. The Company applied this change~~maintained, in ~~accounting principle retrospectively to~~ all ~~prior periods presented.~~

~~We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni S.p.A.’s~~material respects, effective internal control over financial reporting as of December 31, ~~2016,~~2019, based on criteria established in Internal ~~Control-Integrated~~Control — Integrated Framework (2013) issued by the ~~Committee of Sponsoring Organizations of~~COSO.

Change in Accounting Principle

As discussed in Note 3 to the ~~Treadway Commission (2013 framework), and our report dated March 22, 2017 expressed an unqualified opinion thereon.~~consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

~~/s/ Ernst & Young S.p.A.~~Basis for Opinions

~~Rome, Italy~~

~~March 22, 2017~~

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~~Report of Independent Registered Public Accounting Firm~~

~~To the Board of Directors and Shareholders of Eni S.p.A,~~

We have audited Eni S.p.A.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Eni S.p.A.’sThe 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 ~~the accompanying~~ Management’s Annual Report on Internal Control over Financial ~~Reporting.~~Reporting appearing under Item 15. Our responsibility is to express ~~an opinion~~opinions on the ~~company’s~~Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our ~~audit.~~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 ~~audit~~audits in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the ~~audit~~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, and~~risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our ~~audit provides~~audits provide a reasonable basis for our ~~opinion.~~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 ~~(1)~~(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the

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assets of the company; ~~(2)~~(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and ~~(3)~~(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

InCritical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion ~~Eni S.p.A. maintained,~~on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Estimates of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net

As described in ~~all material respects, effective internal control~~Notes 1, 11 and 14 to the consolidated financial statements, the Company’s proved oil and natural gas reserves are used in determining depreciation, amortization, and depletion charges and impairment charges. The Company’s consolidated net carrying amount for Exploration and Production (E&P) property, plant and equipment was €55,467 million at December 31, 2019, and the Company’s depreciation, depletion and amortization (DD&A) expense for E&P wells, plant and machinery was €6,435 million for the year ended December 31, 2019. Additionally, the Company incurred impairment losses before taxes associated with the E&P segment of €1,217 million for the year ended December 31, 2019. Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting. Under this method, proved exploration rights and acquired proved mineral interests are amortized over ~~financial reporting~~proved reserves, and proved exploration and appraisal costs and development expenditures are depreciated over proved developed reserves. The accuracy of reserve estimates depends on a number of factors, assumptions and variables, including: (i) the quality of available geological, technical and economic data and their interpretation and judgement; (ii) projections regarding future rates of production and operating costs as well as the timing and amounts of development expenditures; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of 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 ~~December 31, 2016, based~~the date when these estimates are made.

The principal considerations for our determination that performing procedures relating to the impact of estimates of proved oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are there was significant judgement by management, including the use of specialists, when developing the expected future cash flows and estimates of proved oil and natural gas reserves. This, in turn, led to a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the significant assumptions used in developing those estimates, including production profiles, crude oil and natural gas prices (including price differentials), capital expenditures, operating expenses and abandonment costs.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the ~~COSO criteria.~~consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves, the calculation of DD&A expense and the impairment assessment of proved oil and natural gas properties. These procedures also included, among others, evaluating the methods and significant assumptions used by management in developing these estimates, including production profiles, crude oil and natural gas prices (including price differentials), capital expenditures, operating expenses and

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abandonment costs. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of these estimates of proved oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as their methods and assumptions. The procedures performed also included tests of the data used by management and the specialists and an evaluation of their findings. Evaluating the significant assumptions relating to the estimates of proved oil and natural gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past and current performance of the Company, and whether they were consistent with evidence in other areas of the audit.

Legal Proceedings Concerning Administrative Corporate Responsibility and Other Proceedings

As described in Notes 1 and 27 to the consolidated financial statements, the Company recognizes provisions as liabilities in the consolidated financial statements when (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. Contingent liabilities are: (i) possible obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose 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 actions and administrative arbitral 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.

The principal considerations for our determination that performing procedures relating to legal proceedings concerning administrative corporate responsibility and other proceedings is a critical audit matter are the significant judgement exercised by management when assessing the likelihood of a loss being incurred for the proceedings relating to Block OPL 245 — Nigeria, Congo and Criminal Proceeding no. 12333/2017 can be made, which in turn led to a high degree of auditor judgement, subjectivity, and effort in evaluating management’s assessment of the loss contingencies associated with the legal contingencies.

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 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. These procedures also included, among others, obtaining and evaluating the letters of audit inquiry with external legal counsel, evaluating the reasonableness of management’s assessment regarding whether an unfavorable outcome is reasonably possible or probable, and evaluating the sufficiency of the Company’s legal contingency disclosures. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of management’s assumptions noted above.

PricewaterhouseCoopers SpA (signed)

Rome, Italy

April 2, 2020

We ~~also~~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 ~~in accordance with~~ the ~~standards of the Public Company Accounting Oversight Board (United States), the~~accompanying consolidated balance sheets of Eni S.p.A. (the Company) as of December 31, ~~2016 and 2015, and~~2018, 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 ~~three~~two years in the period ended December 31, ~~2016~~2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our ~~report dated March 22, 2017 expressed~~opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at 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.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an ~~unqualified~~ opinion ~~thereon.~~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/ ~~Ernst & Young~~EY S.p.A.

We served as the Company’s auditor from 2010 to 2018.

Rome, Italy
April 5, 2019

~~March 22, 2017~~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 only and does not form part of Eni S.p.A.’s Annual Report for 2018.

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CONSOLIDATED BALANCE SHEET
(~~euro~~€ million)

January 1, 2015(a)

December 31, 2015(a)
December 31, 2016
Total
amount of which
with related
parties Note Total
amount of which
with related
parties Total
amount of which
with related
parties
ASSETS
Current assets
6,614 Cash and cash equivalents (8) 5,209 5,674
5,024 Financial assets held for trading (9) 5,028 6,166
257 Financial assets available for sale (10) 282 238
28,601 1,973 Trade and other receivables (11) 21,640 1,985 17,593 1,100
7,555 Inventories (12) 4,579 4,637
762 Current tax assets (13) 360 383
1,209 Other current tax assets (14) 630 689
4,385 43 Other current assets (15) (34) 3,642 50 2,591 57
54,407 41,370 37,971
Non-current assets
75,991 Property, plant and equipment (16) 68,005 70,793
1,581 Inventory – compulsory stock (17) 909 1,184
4,420 Intangible assets (18) 3,034 3,269
3,172 Equity-accounted investments (20) 2,853 4,040
2,015 Other investments (20) 660 276
1,042 259 Other financial assets (21) 1,026 396 1,860 1,349
4,509 Deferred tax assets (22) 3,853 3,790
2,773 12 Other non-current assets (23) (34) 1,758 10 1,348 13
95,503 82,098 86,560
456 Discontinued operations and assets held for sale (35) 15,533 308 14
150,366 TOTAL ASSETS 139,001 124,545
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
2,716 181 Short-term debt (24) 5,720 208 3,396 191
3,859 Current portion of long-term debt (29) 2,676 3,279
23,703 1,954 Trade and other payables (25) 14,942 1,544 16,703 2,289
534 Income tax payable (26) 431 426
1,873 Other tax payable (27) 1,454 1,293
4,489 58 Other current liabilities (28) (34) 4,712 96 2,599 88
37,174 29,935 27,696
Non-current liabilities
19,316 Long-term debt (29) 19,397 20,564
15,882 Provisions for contingencies (30) 15,375 13,896
1,313 Provisions for employee benefits (31) 1,123 �� 868
8,590 Deferred tax liabilities (32) 7,425 6,667
2,285 20 Other non-current liabilities (33) (34) 1,852 23 1,768 23
47,386 45,172 43,763
165 Discontinued operations and liabilities directly
associated with assets held for sale (35) 6,485 207
84,725 TOTAL LIABILITIES 81,592 71,459
SHAREHOLDERS’ EQUITY (36)
2,455 Non-controlling interest 1,916 49
Eni shareholders’ equity
4,005 Share capital 4,005 4,005
(284) Reserve related to cash flow hedging derivatives net of tax effect (474) 189
60,763 Other reserves 62,761 52,329
(581) Treasury shares (581) (581)
(2,020) Interim dividend (1,440) (1,441)
1,303 Net profit (loss) (8,778) (1,464)
63,186 Total Eni shareholders’ equity 55,493 53,037
65,641 TOTAL SHAREHOLDERS’ EQUITY 57,409 53,086
150,366 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY 139,001 124,545

January 1, 2018					December 31, 2019		December 31, 2018
Total amount		of which with related parties		Note	Total amount	of which with related parties	Total amount	of which with related parties
			ASSETS
			Current assets
	7,363		Cash and cash equivalents	(5)	5,994		10,836
	6,219		Financial assets held for trading	(6)	6,760		6,552
	316	73	Other current financial assets	(16)	384	60	300	49
	14,156	834	Trade and other receivables	(7)	12,873	704	14,101	633
	4,621		Inventories	(8)	4,734		4,651
	191		Income tax receivables	(9)	192		191
	2,768	30	Other current assets	(10) (23)	3,972	219	2,819	71
	35,634				34,909		39,450
			Non-current assets
	63,158		Property, plant and equipment	(11)	62,192		60,302
			Right-of-use assets	(12)	5,349
	3,012		Intangible assets	(13)	3,059		3,170
	1,283		Inventory – Compulsory stock	(8)	1,371		1,217
	3,474		Equity-accounted investments	(15)	9,035		7,044
	900		Other investments	(15)	929		919
	1,675	1,214	Other non-current financial assets	(16)	1,174	911	1,253	915
	4,315		Deferred tax assets	(22)	4,360		3,931
	182		Income tax receivables	(9)	173		168
	1,141	46	Other non-current assets	(10) (23)	871	181	624	160
	79,140				88,513		78,628
	323		Assets held for sale	(24)	18		295
	115,097		TOTAL ASSETS		123,440		118,373
			LIABILITIES AND SHAREHOLDERS’ EQUITY
			Current liabilities
	2,242	164	Short-term debt	(18)	2,452	46	2,182	661
	2,286		Current portion of long-term debt	(18)	3,156		3,601
			Current portion of long-term lease liabilities	(12)	889	5
	15,305	2,808	Trade and other payables	(17)	15,545	2,663	16,747	3,664
	472		Income tax payables	(9)	456		440
	4,317	60	Other current liabilities	(10) (23)	7,146	155	5,412	63
	24,622				29,644		28,382
			Non-current liabilities
	20,179		Long-term debt	(18)	18,910		20,082
			Long-term lease liabilities	(12)	4,759	8
	13,124		Provisions	(20)	14,106		11,626
	1,022		Provisions for employee benefits	(21)	1,136		1,117
	5,937		Deferred tax liabilities	(22)	4,920		4,272
	359		Income tax payables	(9)	454		287
	1,443	23	Other non-current liabilities	(10) (23)	1,611	23	1,475	23
	42,064				45,896		38,859
	87		Liabilities directly associated with assets held for sale	(24)			59
	66,773		TOTAL LIABILITIES		75,540		67,300
			SHAREHOLDERS’ EQUITY	(25)
	49		Non-controlling interest		61		57
			Eni shareholders’ equity
	4,005		Share capital		4,005		4,005
	36,211		Retained earnings		37,436		36,702
	4,818		Cumulative currency translation differences		7,209		6,605
	1,889		Other reserves		1,564		1,672
	(581)		Treasury shares		(981)		(581)
	(1,441)		Interim dividend		(1,542)		(1,513)
	3,374		Net profit		148		4,126
	48,275		Total Eni shareholders’ equity		47,839		51,016
	48,324		TOTAL SHAREHOLDERS’ EQUITY		47,900		51,073
	115,097		TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		123,440		118,373

See the accompanying notes.

~~(a)~~

~~Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.~~

~~F-3~~F-5

TABLE OF CONTENTS

CONSOLIDATED PROFIT AND LOSS ACCOUNT
(~~euro~~€ million except as otherwise stated)


			2014(a)				2015(a)				2016						2019				2018				2017
	Note		Total amount		of which with related parties		Total amount		of which with related parties		Total amount		of which with related parties
REVENUES		(39)
Net sales from operations				98,218		1,497		72,286		1,342		55,762		1,238
															Note		Total amount		of which with related parties		Total amount		of which with related parties		Total amount		of which with related parties
REVENUES AND OTHER INCOME															(28)
Sales from operations																		69,881		1,248		75,822		1,383		66,919		1,567
Other income and revenues				1,079		69		1,252		69		931		74				1,160		4		1,116		8		4,058		41
				99,297				73,538				56,693						71,041				76,938				70,977
OPERATING EXPENSES		(40)
COSTS
Purchases, services and other				77,404		7,143		56,848		6,882		44,124		8,212	(29)			(50,874)		(9,173)		(55,622)		(8,009)		(51,548)		(9,164)
Net (impairment losses) reversals of trade and other receivables															(7)			(432)		28		(415)		26		(913)
Payroll and related costs				2,929		60		3,119		55		2,994		24	(29)			(2,996)		(28)		(3,093)		(22)		(2,951)		(34)
OTHER OPERATING (EXPENSE) INCOME		(40)		145		208		(485)		96		16		247
Other operating income (expense)															(23)	��		287		19		129		319		(32)		331
Depreciation and amortization		(40)		7,676				8,940				7,559			(11) (12) (13)			(8,106)				(6,988)				(7,483)
Net Impairments/reversal		(40)		1,270				6,534				(475)
Net (impairment losses) reversals of tangible and intangible assets and right-of-use assets															(14)			(2,188)				(866)				225
Write-off of tangible and intangible assets		(40)		1,198				688				350			(11) (13)			(300)				(100)				(263)
OPERATING PROFIT (LOSS)				8,965				(3,076)				2,157
OPERATING PROFIT																		6,432				9,983				8,012
FINANCE INCOME (EXPENSE)		(41)
Finance income				5,701		46		8,635		83		5,850		157	(30)			3,087		96		3,967		115		3,924		191
Finance expense				(7,057)		(41)		(10,104)		(50)		(6,232)		(145)	(30)			(4,079)		(36)		(4,663)		(283)		(5,886)		(4)
Net Finance income from financial assets held for trading				24				3				(21)
Derivatives financial instruments				165				160				(482)		27
Net finance income (expense) from financial assets held for trading															(30)			127				32				(111)
Derivative financial instruments															(23) (30)			(14)				(307)				837
				(1,167)				(1,306)				(885)						(879)				(971)				(1,236)
INCOME (EXPENSE) FROM INVESTMENTS		(42)													(15) (31)
Share of profit (loss) from equity-accounted investments				110				(471)				(326)						(88)				(68)				(267)
Other gain (loss) from investments				366				576				(54)						281				1,163				335
				476				105				(380)						193				1,095				68
PROFIT BEFORE INCOME TAXES				8,274				(4,277)				892						5,746				10,107				6,844
Income taxes		(43)		(6,466)				(3,122)				(1,936)			(32)			(5,591)				(5,970)				(3,467)
Net profit (loss) for the year - Continuing operations				1,808				(7,399)				(1,044)
Net profit (loss) for the year - Discontinued operations		(35)		(949)		867		(1,974)		142		(413)
Net profit (loss) for the year				859				(9,373)				(1,457)
Net profit																		155				4,137				3,377
Attributable to Eni																		148				4,126				3,374
– continuing operations				1,720				(7,952)				(1,051)
– discontinued operations		(35)		(417)				(826)				(413)
				1,303				(8,778)				(1,464)
Attributable to non-controlling interest		(36)																7				11				3
- continuing operations				88				553				7
- discontinued operations		(35)		(532)				(1,148)
				(444)				(595)				7						155				4,137				3,377
Earnings per share attributable to Eni (€ per share)		(44)													(33)
Basic				0.36				(2.44)				(0.41)						0.04				1.15				0.94
Diluted				0.36				(2.44)				(0.41)						0.04				1.15				0.94
Earnings per share attributable to Eni - Continuing operations (€ per share)		(44)
Basic				0.48				(2.21)				(0.29)
Diluted				0.48				(2.21)				(0.29)

See the accompanying notes.

~~(a)~~

~~Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.~~

~~F-4~~F-6

TABLE OF CONTENTS

CONSOLIDATED ~~STATEMENTS~~STATEMENT OF COMPREHENSIVE INCOME
(~~euro~~€ million)

Note
2014(a)

2015(a)
2016
Net profit 859 (9,373) (1,457)
Other items of comprehensive income
Items that are not reclassified to profit in later periods
Remeasurements of defined benefit plans
(36)
(82) 36 16
Share of other comprehensive income on equity accounted entities in relation to remeasurements of defined benefit plans
(36)
3
Tax effect related to other comprehensive income
not to be reclassified to profit or loss in
subsequent periods
(36)
22 (21) (35)
(57) 15 (19)
Items that may be reclassified to profit in later periods
Currency translation differences
(36)
5,427 4,837 1,198
Change in the fair value of available-for-sale investments
(36)
(77)
Change in the fair value of other available-for-sale financial instruments
(36)
7 (4) (4)
Change in the fair value of cash flow hedging derivatives
(36)
(167) (256) 883
Share of other comprehensive income on equity-accounted entities
(36)
4 (9) 32
Tax effect related to other comprehensive income
to be reclassified to profit or loss in subsequent
periods
(36)
30 66 (220)
5,224 4,634 1,889
Total other items of comprehensive income 5,167 4,649 1,870
Total comprehensive income 6,026 (4,724) 413
Attributable to Eni
- continuing operations 6,817 (3,416) 819
- discontinued operations
(35)
(390) (779) (413)
6,427 (4,195) 406
Attributable to non-controlling interest
- continuing operations 91 554 7
- discontinued operations
(35)
(492) (1,083)
(401) (529) 7


	Note		2019		2018		2017
Net profit				155		4,137		3,377
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)
Share of other comprehensive income (loss) on equity-accounted investments related to benefit plans remeasurements		(25)		(7)
Change of minor investments measured at fair value with effects to other comprehensive income		(25)		(3)		15
Tax effect		(25)		5		(2)		29
				(47)		(2)		(4)
Items that may be reclassified to profit or loss in later periods
Currency translation differences		(25)		604		1,787		(5,573)
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)
Share of other comprehensive income (loss) on equity-accounted investments		(25)		(6)		(24)		69
Tax effect		(25)		197		58		1
				116		1,578		(5,514)
Total other items of comprehensive income (loss)				69		1,576		(5,518)
Total comprehensive income (loss)				224		5,713		(2,141)
Attributable to Eni				217		5,702		(2,144)
Attributable to non-controlling interest				7		11		3
				224		5,713		(2,141)

See the accompanying notes.

~~(a)~~

~~Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.~~

~~F-5~~F-7

TABLE OF CONTENTS

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(~~euro~~€ million)

Eni shareholders’ equity
Note Share
capital Legal
reserve of
Eni SpA Reserve for
treasury
shares Reserve
related to
the fair
value of
cash flow
hedging
derivatives
net of the
tax effect Reserve
related to
the fair
value of
available-
for-sale
financial
instruments
net of the
tax effect Reserve for
defined
benefit
plans net of
the tax effect Other
reserves Cumulative
currency
translation
differences Treasury
shares Retained
earnings Interim
dividend Net profit
(loss) for
the year Other
comprehensive
income (loss)
related to
discontinued
operations Total Non-
controlling
interest Total
shareholders’
equity
Balance at December 31, 2013 4,005 959 6,201 (154) 81 (72) 296 (698) (201) 44,626 (1,993) 5,160 58,210 2,839 61,049
Changes in accounting principles (SEM) 3,001 3,001 3 3,004
Balance at January 1, 2014 4,005 959 6,201 (154) 81 (72) 296 (698) (201) 47,627 (1,993) 5,160 61,211 2,842 64,053
Net profit (loss) for the year 1,303 1,303 (444) 859
Other items of comprehensive income
Items that are not reclassified to profit in later periods
Remeasurements of defined benefit plans net of
tax effect (51) (51) (9) (60)
Share of “Other comprehensive income” on
equity-accounted entities in relation to
remeasurements of defined benefit plans net of
tax effect 2 2 1 3
(49) (49) (8) (57)
Items that may be reclassified to profit in later periods
Currency translation differences (1) 5,137 232 5,368 59 5,427
Change and reversal of the fair value of investments net of tax effect (76) (76) (76)
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect 6 6 6
Change and reversal the fair value of cash flow
hedge derivatives net of tax effect (130) (130) (7) (137)
Share of “Other comprehensive income” on equity-accounted entities 5 5 (1) 4
(130) (70) (1) 5 5,137 232 5,173 51 5,224
Total comprehensive income of the year (130) (70) (50) 5 5,137 232 1,303 6,427 (401) 6,026
Transactions with shareholders
Dividend distribution of Eni SpA (€0.55 per
share in settlement of 2013 interim dividend of
€0.55 per share) 1,993 (3,979) (1,986) (1,986)
Interim dividend distribution of Eni SpA (€0.56
per share) (2,020) (2,020) (2,020)
Dividend distribution of other companies (49) (49)
Allocation of 2013 net profit 1,181 (1,181)
Acquisition of treasury shares (380) (380) (380)
Payments and reimbursements by/to minority shareholders �� 1 1
(380) 1,181 (27) (5,160) (4,386) (48) (4,434)
Other changes in shareholders’ equity
Elimination of intercompany profit between companies with different Group interest (62) (62) 62
Stock options expired (7) (7) (7)
Other changes (94) 97 3 3
(94) 28 (66) 62 (4)
Balance at December 31, 2014 (36) 4,005 959 6,201 (284) 11 (122) 207 4,439 (581) 49,068 (2,020) 1,303 63,186 2,455 65,641
Net profit (loss) for the year (8,778) (8,778) (595) (9,373)
Other items of comprehensive income
Items that are not reclassified to profit in later periods
Remeasurements of defined benefit plans net of
tax effect (36) 14 14 1 15
Reclassification of “Other comprehensive loss”
related to discontinued operations (35) (36) 8 (8)
22 (8) 14 1 15
Items that may be reclassified to profit in later periods
Currency translation differences (36) (1) 4,722 54 4,775 62 4,837
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect (36) (3) (3) (3)
Change and reversal the fair value of cash flow
hedge derivatives net of tax effect (36) (194) (194) 3 (191)
Share of “Other comprehensive income” on equity-accounted entities (36) (9) (9) (9)
Reclassification of “Other comprehensive income” related to discontinued operations (35) (36) 4 (32) 28
(190) (3) (1) (9) 4,690 54 28 4,569 65 4,634
Total comprehensive income of the year (190) (3) 21 (9) 4,690 54 (8,778) 20 (4,195) (529) (4,724)
Transactions with shareholders
Dividend distribution of Eni SpA (€0.56 per
share in settlement of 2014 interim dividend of
€0.56 per share) (36) 2,020 (4,037) (2,017) (2,017)
Interim dividend distribution of Eni SpA (€0.40
per share) (36) (1,440) (1,440) (1,440)
Dividend distribution of other companies (21) (21)
Allocation of 2014 net loss (2,734) 2,734
Payments and reimbursements by/to minority shareholders (36) 1 1
(2,734) 580 (1,303) (3,457) (20) (3,477)
Other changes in shareholders’ equity
Elimination of intercompany profit between companies with different Group interest (28) (28) 28
Exclusion from the scope of consolidation of non-significant companies and changes in non-controlling interests (7) (7) (10) (17)
Reclassification of the reserve for treasury shares (5,620) 5,620
Other changes (18) 12 (6) (8) (14)
(5,620) (18) 5,597 (41) 10 (31)
Balance at December 31, 2015 (36) 4,005 959 581 (474) 8 (101) 180 9,129 (581) 51,985 (1,440) (8,778) 20 55,493 1,916 57,409

		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

See the accompanying notes.

~~F-6~~F-8

TABLE OF CONTENTS

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued)
(~~euro~~€ million)

		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, 2017			4,005		35,966		4,818		1,889		(581)		(1,441)		3,374		48,030		49		48,079
Changes in accounting policies (IFRS 9 and 15)					245												245				245
Balance at January 1, 2018			4,005		36,211		4,818		1,889		(581)		(1,441)		3,374		48,275		49		48,324
Net profit for the year															4,126		4,126		11		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 net of tax effect	(25)								(17)								(17)				(17)
Change of minor investments measured at fair value with effects to OCI	(25)								15								15				15
									(2)								(2)				(2)
Items that may be reclassified to profit or loss in later periods
Currency translation differences	(25)						1,787										1,787				1,787
Change in the fair value of cash flow hedge derivatives net of tax effect	(25)								(185)								(185)				(185)
Share of “Other comprehensive income (loss)” on equity-accounted investments	(25)								(24)								(24)				(24)
							1,787		(209)								1,578				1,578
Total comprehensive income (loss) of the year							1,787		(211)						4,126		5,702		11		5,713
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per share in settlement of 2017 interim dividend of €0.40 per share)	(25)												1,441		(2,881)		(1,440)				(1,440)
Interim dividend distribution of Eni SpA (€0.42 per share)	(25)												(1,513)				(1,513)				(1,513)
Dividend distribution of other companies																			(3)		(3)
Allocation of 2017 net income					493										(493)
					493								(72)		(3,374)		(2,953)		(3)		(2,956)
Other changes in shareholders’ equity
Long-term share-based incentive plan					5												5				5
Other changes					(7)				(6)								(13)				(13)
					(2)				(6)								(8)				(8)
Balance at December 31, 2018	(25)		4,005		36,702		6,605		1,672		(581)		(1,513)		4,126		51,016		57		51,073

See the accompanying notes.

~~F-7~~F-9

TABLE OF CONTENTS

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued)
(€ million)

	Eni shareholders’ equity
	Share capital	Retained earnings		Cumulative currency translation differences		Other reserves		Treasury shares		Interim dividend		Net profit (loss) for the year		Total		Non- controlling interest		Total shareholders’ equity
Balance at December 31, 2016	4,005		40,367		10,319		1,832		(581)		(1,441)		(1,464)		53,037		49		53,086
Net profit for the year													3,374		3,374		3		3,377
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							(4)								(4)				(4)
							(4)								(4)				(4)
Items that may be reclassified to profit or loss in later periods
Currency translation differences					(5,575)		2								(5,573)				(5,573)
Change in the fair value of other available-for-sale financial instruments net of tax effect		��					(4)								(4)				(4)
Change in the fair value of cash flow hedge derivatives net of tax effect							(6)								(6)				(6)
Share of “Other comprehensive income (loss)” on equity-accounted investments							69								69				69
					(5,575)		61								(5,514)				(5,514)
Total comprehensive income (loss) of the year					(5,575)		57						3,374		(2,144)		3		(2,141)
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per share in settlement of 2016 interim dividend of €0.40 per share)											1,441		(2,881)		(1,440)				(1,440)
Interim dividend distribution of Eni SpA (€0.40 per share)											(1,441)				(1,441)				(1,441)
Dividend distribution of other companies																	(3)		(3)
Allocation of 2016 net loss			(4,345)										4,345
			(4,345)										1,464		(2,881)		(3)		(2,884)
Other changes in shareholders’ equity
Other changes			(56)		74										18				18
			(56)		74										18				18
Balance at December 31, 2017	4,005		35,966		4,818		1,889		(581)		(1,441)		3,374		48,030		49		48,079

F-10

TABLE OF CONTENTS

CONSOLIDATED STATEMENT OF CASH FLOWS
(~~euro~~€ million)


	Note		2014(a)			2015(a)			2016		Note	2019		2018		2017
Net profit (loss) of the year – Continuing operations				1,808			(7,399)			(1,044)
Net profit													155		4,137		3,377
Adjustments to reconcile net profit to net cash provided by operating activities
Depreciation and amortization		(40)		7,676			8,940			7,559	(11) (12) (13)		8,106		6,988		7,483
Net Impairments/reversal		(40)		1,270			6,534			(475)
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		(40)		1,198			688			350	(11) (13)		300		100		263
Share of (profit) loss of equity-accounted investments		(42)		(110)			471			326	(15) (31)		88		68		267
Gain on disposal of assets, net				(224)			(577)			(48)
Net gain on disposal of assets													(170)		(474)		(3,446)
Dividend income		(42)		(385)			(402)			(143)	(31)		(247)		(231)		(205)
Interest income				(162)			(164)			(209)			(147)		(185)		(283)
Interest expense				681			659			645			1,027		614		671
Income taxes		(43)		6,466			3,122			1,936	(32)		5,591		5,970		3,467
Other changes				852			586			(9)			(179)		(474)		894
Changes in working capital:
- inventories	1,620				1,638			(273)					(200)		15		(346)
- trade receivables	2,051				4,944			1,286					1,023		334		657
- trade payables	(1,669)				(2,342)			1,495					(940)		642		284
- provisions for contingencies	(234)				43			(1,043)
- provisions													272		(238)		96
- other assets and liabilities	431				498			647					211		879		749
Cash flow from changes in working capital				2,199			4,781			2,112			366		1,632		1,440
Net change in the provisions for employee benefits				12			(3)			22			(23)		109		38
Dividends received				603			545			212			1,346		275		291
Interest received				107			81			160			88		87		104
Interest paid				(851)			(692)			(780)			(1,029)		(609)		(582)
Income taxes paid, net of tax receivables received				(6,671)			(4,295)			(2,941)			(5,068)		(5,226)		(3,437)
Net cash provided by operating activities – Continuing operations				14,469			12,875			7,673
Net cash provided by operating activities – Discontinued operations		(35)		273			(1,226)
Net cash provided by operating activities				14,742			11,649			7,673			12,392		13,647		10,117
- of which with related parties		(47)		(3,203)			(3,966)			(3,749)	(36)		(6,356)		(2,707)		(2,843)
Investing activities:
- tangible assets		(16)		(11,646)			(11,177)			(9,067)	(11)		(8,049)		(8,778)		(8,490)
- prepaid right-of-use assets											(12)		(16)
- intangible assets		(18)		(226)			(125)			(113)	(13)		(311)		(341)		(191)
- consolidated subsidiaries and businesses net of cash and cash equivalent acquired		(37)		(36)							(26)		(5)		(119)
- investments		(20)		(372)			(228)			(1,164)	(15)		(3,003)		(125)		(510)
- securities				(77)			(201)			(1,336)
- financing receivables				(1,289)			(1,103)			(1,208)
- change in payables in relation to investing activities and capitalized depreciation				669			(1,058)			(8)
- 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				(12,977)			(13,892)			(12,896)			(11,928)		(9,321)		(9,624)
Disposals:
- tangible assets				104			427			19			264		1,089		2,745
- intangible assets				1			32						17		5		2
- consolidated subsidiaries and businesses net of cash and cash equivalent disposed of		(37)					73			(362)	(26)		187		(47)		2,662
- tax on disposals													(3)				(436)
- investments				3,579			1,726			508			39		195		482
- securities				57			18			20
- financing receivables				506			533			8,063
- securities held for operating purposes													17		15		1
- financing receivables held for operating purposes													178		279		493
- change in receivables in relation to disposals				155			160			205			95		606		(434)
Cash flow from disposals				4,402			2,969			8,453			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				(8,575)			(10,923)			(4,443)			(11,413)		(7,536)		(3,768)
- of which with related parties		(47)		(1,458)			(1,583)			3,752	(36)		(2,912)		(3,314)		(3,115)

See the accompanying notes.

(a)

~~Information on~~From 2019, Eni’s cash flow statement is reporting in a dedicated line-item the ~~restatement~~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 ~~data in application of IAS 8 is reported in note 5 — Changes in accounting principles.~~periods have been reclassified accordingly.

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CONSOLIDATED STATEMENT OF CASH FLOWS (continued)
(~~euro~~€ million)


	Note		2014 (a)		2015 (a)		2016
									Note	2019		2018		2017
Increase in long-term financial debt		(29)		1,916		3,376		4,202	(18)		1,811		3,790		1,842
Repayments of long-term financial debt		(29)		(2,751)		(4,466)		(2,323)	(18)		(3,512)		(2,757)		(2,973)
Payments of lease liabilities									(12)		(877)
Increase (decrease) in short-term financial debt		(24)		207		3,216		(2,645)	(18)		161		(713)		(581)
				(628)		2,126		(766)			(2,417)		320		(1,712)
Net capital contributions by non-controlling interest				1		1
Dividends paid to Eni’s shareholders				(4,006)		(3,457)		(2,881)			(3,018)		(2,954)		(2,880)
Dividends paid to non-controlling interest				(49)		(21)		(4)			(4)		(3)		(3)
Reimbursements to non-controlling interest											(1)
Acquisition of additional interests in consolidated subsidiaries											(1)
Acquisition of treasury shares				(380)							(400)
Net cash used in financing activities				(5,062)		(1,351)		(3,651)			(5,841)		(2,637)		(4,595)
- of which with related parties		(47)		(99)		13		(192)	(36)		(817)		16		(16)
Effect of change in consolidation (inclusion/ exclusion of significant/insignificant subsidiaries)				2		(13)		(5)
Effect of cash and cash equivalents pertaining to discontinued operations		(37)				(889)		889
Effect of exchange rate changes on cash and cash equivalents and other changes				76		122		2
Net cash flow of the year				1,183		(1,405)		465
Cash and cash equivalents - beginning of the year (excluding discontinued operations)		(8)		5,431		6,614		5,209
Cash and cash equivalents - end of the year (excluding discontinued operations)		(8)		6,614		5,209		5,674

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)
Net increase (decrease) in cash and cash equivalents											(4,861)		3,492		1,689
Cash and cash equivalents – beginning of the year									(5)		10,855		7,363		5,674
Cash and cash equivalents – end of the year(b)									(5)		5,994		10,855		7,363

See the accompanying notes.

~~(a)~~(b)

~~Information on~~In 2018, cash and cash equivalents at the ~~restatement~~end of ~~comparative data in application~~the year included €19 million of ~~IAS 8 is~~cash and cash equivalents of consolidated subsidiaries held for sale that were reported in ~~note 5 — Changes in accounting principles.~~the item “Assets held for sale”.

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Notes on Consolidated Financial Statements

1 Significant accounting policies, estimates and judgements

Basis of preparation

The Consolidated Financial Statements of the Eni Group have been prepared on a going concern basis in accordance with International Financial Reporting Standards (IFRS)1 as issued by the International Accounting Standards Board (IASB). Oil and natural gas exploration and production activity is accounted for in accordance with internationally accepted accounting standards taking into account the requirements in IFRSs that apply. In particular, starting from January 1, 2016, Eni has adopted, on a voluntary basis, the so-called Successful Efforts Method (hereinafter also SEM) to recognize and measure costs related to exploration activities, in order to improve the comparability of Eni’s results with those of the competitors, as well as to ensure financial reporting that is proper, reliable and consistent with the decision-making processes related to the evaluation of the exploration and production activities’ results. The recognition and measurement criteria for the oil&gas exploration and production activities are indicated in the accounting policy for “Oil and natural gas exploration, appraisal, development and production expenditure”; the effects arising from the adoption of SEM are indicated in note 5 “Changes in accounting policies”.

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 ~~note 3 “Significant~~ accounting ~~policies”.~~policies that follow.

The ~~2016~~2019 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on March ~~17, 2017,~~18, 2020, were audited by the external auditor ~~Ernst & Young~~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, ~~Ernst & Young~~PricewaterhouseCoopers SpA takes the responsibility of their work.

~~Amounts~~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, ~~and~~as well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are ~~expressed~~based on complex judgements and past experience of other assumptions deemed reasonable in ~~millions~~consideration of ~~euros (euro million).~~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.

2 Principles of consolidation

Subsidiaries

The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its ~~Italian and foreign~~ 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.

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; 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 attributable to non-controlling interests is presented in a specific line item of the profit and loss account.

For entities acting as sole-operator in the management of oil~~&gas~~ and gas contracts on behalf of companies participating in a joint project, 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 ~~revenues~~revenue and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are ~~recognized~~recognised directly in the financial statements of the companies involved based on their own share. Some subsidiaries are not consolidated because they are immaterial, either individually or in the aggregate; this exclusion has not produced ~~significant~~material2 effects on the Consolidated Financial ~~Statements.~~

~~(1)~~

IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations issued by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC)Statements3.

~~(2)~~

According to the requirements of the Conceptual Framework for IFRS, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”.

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~~TABLE OF CONTENTS~~

Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases. 100% of assets, liabilities, income and expenses of consolidated subsidiaries are combined with those of the parent in the Consolidated Financial Statements; the net book value of these subsidiaries is eliminated against the corresponding portion of the shareholders’ equity. Equity and net profit attributable to non-controlling interests are included in specific line items of equity and profit and loss account.

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 non-controlling interests are adjusted is attributed to ~~the Group~~Eni shareholders’ equity. Conversely, the sale of equity interests with loss of control determines the recognition in the profit and loss account of: (i) any ~~gain/~~gain or loss calculated as the difference between the consideration received and the corresponding transferred ~~portion of equity;~~net assets; (ii) any gain or loss ~~recognized~~recognised as a result of the ~~re-measurement~~remeasurement of any investment retained in the former subsidiary toat its fair value; and (iii) any amount related to the former subsidiary previously ~~recognized~~recognised in other comprehensive income which ~~can~~may be reclassified subsequently to the profit and loss account34. Any investment retained in the former subsidiary is ~~recognized~~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

~~A joint arrangement is an arrangement of which two or more parties have joint control.~~ 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. Judgment is required in assessing whether a joint arrangement creates enforceable rights and obligations; this assessment is made considering the design and purpose of the joint arrangement, the terms of the contractual arrangements, as well as any other facts and circumstances that are relevant for this assessment. In the Consolidated Financial Statements, ~~the Eni’s~~Eni recognises its share of the assets/liabilities and ~~revenues/~~revenue/expenses of joint operations ~~is recognized upon~~on the basis of its rights and obligations relating to the arrangements.

After the initial recognition, the assets/liabilities and ~~revenues/~~revenue/expenses of the joint operations are measured in accordance with the applicable measurement ~~criteria applicable to each case.~~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.

~~Interests~~Investments in associates

An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

According to the requirements of the Conceptual Framework for Financial Reporting, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”.

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

Conversely, any amount related to the former subsidiary previously recognised in other comprehensive income, which may not be reclassifiedsubsequently 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 audit also the information required for the preparation of the Consolidated Financial Statements.

~~(3)~~

Conversely, any amount related to the former subsidiary previously recognized in other comprehensive income, which cannot be reclassified subsequently to the profit and loss account, are reclassified within retained earnings.

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The equity method of accounting

Investments in ~~immaterial subsidiaries,~~ joint ventures, associates and ~~associates~~immaterial unconsolidated subsidiaries, are accounted for using the equity ~~method~~method.45 6.

Under the equity method, investments are initially ~~recognized~~recognised at cost, allocating, similarly to business combinations procedures, the purchase price of the investment to the investee’s identifiable assets/liabilities; if this allocation is provisionally ~~recognized~~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. Changes in the net assets of an equity-accounted investee, not arising from the investee’s profit or loss or other comprehensive income, are recognized in the investor’s profit and loss account, as they basically represent a gain or loss from a disposal of an interest in the investee’s equity. 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”). ~~When~~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 ~~(see also~~(e.g. relevant breaches of contracts, significant financial difficulty, probable default of the ~~accounting policy for “Current financial assets”~~counterparty, etc.), the ~~recoverability~~net investment is tested for impairment by comparing ~~the~~its carrying amount ~~and~~with the related recoverable amount, determined by adopting the criteria indicated in the accounting policy for ~~“Property, plant and equipment”. Immaterial subsidiaries, joint ventures and associates are accounted for at cost, net~~“Impairment of ~~any impairment losses, if this does not result in a misrepresentation of the Group financial position and performance.~~non-financial assets”. When an impairment loss no longer exists or has decreased, aany reversal of the impairment loss is ~~recognized~~recognised in the profit and loss account within ~~“Other gain (loss)~~“Income (Expense) from investments”. The impairment reversal ~~cannot~~of the net investment shall not exceed the previously ~~recognized~~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/~~gain or loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss ~~recognized~~recognised as a result of the ~~re-measurement~~remeasurement of any investment retained in the former joint venture/associate toat its fair value57; and (iii) any amount related to the former joint venture/associate previously ~~recognized~~recognised in other comprehensive income which ~~can~~may be reclassified subsequently to the profit and loss account68. Any investment retained in the former joint venture/associate is ~~recognized~~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.

The investor’s share of losses of an equity-accounted investee, that exceeds the carrying amount of the investment, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to fund its losses.

Business combinations

Business combinations are ~~recognized~~accounted for by applying the acquisition method. The consideration transferred in a business combination is ~~measured at the acquisition date and is~~ the sum of the acquisition-date fair ~~values~~value of the assets transferred, the liabilities incurred ~~as well as any~~and the equity ~~instruments~~interests issued by the acquirer. Acquisition-related costs are accounted for as expenses when ~~they are~~ incurred.

~~At the acquisition date, the acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values~~7, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed is recognized as goodwill; a gain from a bargain purchase is recognized in the profit and loss account.

~~(4)~~5

In the case of step acquisition of significant influence ~~(or joint~~(joint control), the investment is ~~recognized,~~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.

~~(5)~~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.

If the retained investment continues to be accounted for using the equity method, no remeasurement toat fair value is ~~recognized~~recognised in the profit and loss account.

~~(6)~~8

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

~~(7)~~

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

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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 ~~interest is~~interests are measured as the proportionate share in the ~~recognized~~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, ~~it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, including also the goodwill attributable to~~ non-controlling interests ~~(full goodwill method). In the last case, non-controlling interests are~~may be measured at ~~their~~ fair value, which ~~therefore~~means that goodwill includes the ~~goodwill~~portion attributable to them (full goodwill method)810. The choice of measurement basis offor 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 ~~the acquisition of~~obtaining control; the previously held equity interests are ~~re-measured~~remeasured at their acquisition-date fair value and the resulting gain or loss, if any, is ~~recognized~~recognised in the profit and loss account. Furthermore, on obtaining control, any amount ~~of the acquiree previously recognized~~recognised in other comprehensive income related to the previously held equity interests is ~~charged~~reclassified to the profit and loss account, or in another item of equity when ~~the~~such amount ~~cannot~~may not be reclassified to the profit and loss account. ~~If control is obtained over a business formerly classified as joint operation, the previously held interest in its assets and liabilities is not re-measured to its fair value.~~

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts ~~recognized~~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 ~~in which the~~whose activity constitutes a business is ~~recognized~~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 and obligations imply that the management makes complex judgements on the basis of the characteristics of the investee’s structure, arrangements between parties and other relevant ~~principles~~facts and circumstances. Significant accounting estimates by management are required also for measuring the identifiable assets acquired and the liabilities assumed in a business ~~combinations.~~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 ~~unrealized~~unrealised profits arising from such transactions have been eliminated.

~~Unrealized~~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, ~~unrealized~~unrealised losses are not eliminated ~~when they provide~~unless the transaction provides evidence of an impairment loss of the asset transferred.

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

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.

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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Foreign currency translation

The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency, are translated into ~~euro~~euros using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows (source: ~~WMR/IPSE)~~Reuters — WMR).

The cumulative ~~amount of the~~ resulting ~~translation~~exchange differences isare presented in the separate component of ~~the Group~~Eni shareholders’ equity “Cumulative currency translation differences”912. 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 athat foreign operation or when the partial disposal involves the loss of control, joint control or significant influence ~~of a~~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.

~~(8)~~

~~The choice between 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.~~

~~(9)~~

When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognized as part of “Non-controlling interest”.

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The financial statements of foreign operations which are translated into ~~euro~~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 2014		Exchange rate at December 31, 2014		Annual average exchange rate 2015		Exchange rate at December 31, 2015		Annual average exchange rate 2016		Exchange rate at December 31, 2016		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
U.S. Dollar		1.33		1.21		1.11		1.09		1.11		1.05		1.12		1.12		1.18		1.15		1.13		1.20
Pound Sterling		0.81		0.78		0.73		0.73		0.82		0.86		0.88		0.85		0.88		0.89		0.88		0.89
Norwegian Krone		8.35		9.04		8.95		9.60		9.29		9.09
Australian Dollar		1.47		1.48		1.48		1.49		1.49		1.46		1.61		1.60		1.58		1.62		1.47		1.53

3 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 ~~expenditure~~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 ~~capitalized~~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 ~~amortized,~~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 ~~can show~~indicate the ~~existence~~absence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is ~~recognized~~recognised in the profit and loss account as write-off. Lower value exploration rights are pooled and ~~amortized~~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

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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proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. ~~When the~~Upon reclassification, ~~is recognized, as well as whether~~or when there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration rights are ~~amortized~~amortised according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and ~~amortization”~~amortisation”).

Acquisition of mineral interests

Costs incurred for the acquisition of mineral interests are ~~capitalized~~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 ~~under~~in accordance with the criteria ~~indicated~~illustrated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are ~~amortized on a~~amortised according to the UOP ~~basis~~method (see the accounting policy for “UOP depreciation, depletion and ~~amortization”~~amortisation”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not ~~amortized~~amortised until classified as proved reserves; in case of a negative result, it is ~~written-off.~~written off.

Exploration and appraisal expenditure

Geological and geophysical exploration costs are ~~recognized~~recognised as an expense as incurred.

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Costs directly associated with an exploration well are initially ~~recognized~~recognised within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be ~~capitalized~~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 ~~capitalized~~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 ~~capitalized~~capitalised costs are ~~recognized~~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 ~~recognized~~recognised as unproved is reclassified to proved exploration and appraisal costs within tangible assets in progress. ~~When the~~Upon reclassification, ~~is recognized,~~ as well as whether there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and ~~amortization”~~amortisation”).

Development expenditure

Development expenditure, including the costs related to unsuccessful and damaged development wells, are ~~capitalized~~capitalised as “Tangible asset in progress — proved”. Development ~~expenditures~~costs are ~~costs~~ incurred to obtain access to proved reserves and to provide facilities ~~to extract, gather~~for extracting, treating, gathering and ~~store~~storing the oil~~&gas.~~ and gas. They are ~~amortized,~~amortised, from the commencement of production, generally on a UOP ~~basis (see the accounting policy for “UOP depreciation, depletion and amortization”).~~basis. When development projects are unfeasible/not carried on, the related costs are ~~written-off~~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 ~~amortization~~amortisation

Proved oil~~&gas~~ and gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of proved oil~~&gas~~ 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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method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil~~&gas~~ and gas reserves. Proved exploration rights and acquired proved mineral interests are ~~amortized~~amortised over proved reserves; proved exploration and appraisal costs and development expenditure are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves.

Production costs

Production costs are those costs incurred to operate and maintain wells and field equipment and are ~~recognized~~recognised as an expense as incurred.

Production Sharing Agreements and buy-back 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, ~~entitlements~~ 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 ~~representing the Profit Oil~~ includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to ~~recognize~~recognise at the same time an increase in the taxable profit, through the increase of the ~~revenues,~~revenue, and a tax expense.

~~Decommissioning~~Plugging and ~~restoration liabilities~~abandonment of wells

Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are ~~capitalized, consistently~~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.

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 reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. 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 ~~recognized~~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. ~~When~~For assets that necessarily take a substantial period of time ~~is required~~ to ~~make the asset~~get ready for their intended use, the purchase price or construction cost ~~includes~~comprises the borrowing costs incurred in the period to get the asset ready for use that ~~could~~would have ~~otherwise~~ 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~~occurs; a corresponding amount is ~~recognized~~recognised as part of a specific ~~provision). Changes in provisions due to the passage of time and changes in discount rates are recognized as described in~~provision (see the accounting policy for ~~“Provisions, contingent assets~~“Decommissioning and restoration liabilities”10.

Property, plant and equipment are not revalued for financial reporting purposes.

Assets under finance lease, or under arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset, are recognized, at the commencement of the lease term, at fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt to the lessor is recognized. These assets are depreciated as described below. If there is no reasonable certainty that the lessee will obtain ownership by the end of the lease term, the assets are depreciated over the shorter of the lease term and the useful life of the asset.

Expenditures on upgrading, revamping and reconversion are ~~recognized~~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 ~~to obtain future economic benefits from other assets.~~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 ~~using a straight-line method~~ 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 ~~purchased~~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” ~~below)~~). ~~A change in the depreciation method, deriving from changes~~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, ~~shall be recognized~~are accounted for prospectively.

Assets ~~that can~~to be ~~used free of charge by third parties~~handed over for no consideration are depreciated over the shorter term ofbetween the duration of the concession or the asset’s useful life.

Replacement costs of identifiable parts in complex assets are ~~capitalized~~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. ~~Leasehold improvement costs~~Non-removable leasehold improvements are depreciated over the earlier of the useful life of the improvements ~~or, if lower, over the residual length of~~and the lease ~~considering any renewal period if renewal depends entirely on the lessee and is virtually certain.~~term. Expenditures for ordinary maintenance and repairs are ~~recognized~~recognised as an expense as incurred.

The carrying amount of property, plant and equipment is reviewed for impairment whenever there is any indication that the carrying amounts of those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the

These liabilities relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with tangible assets of Refining & Marketing, Chemical and Gas & Power segments/businesses are recognized when the amount of the liability can be reliably estimated, considering that undetermined settlement dates for assets dismantlement and restoration do not allow a discounting estimate of the obligation. With regard to this, Eni performs periodic reviews of its tangible assets of Refining & Marketing, Chemical and Gas & Power segments/businesses for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.

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asset’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 asset 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. 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 asset, giving greater weight to external evidence.

With reference to commodity prices, management assumes the price scenario adopted for economic and financial projections and for whole life appraisal for capital expenditures. In particular, for the cash flows associated to 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 long-term planning assumptions and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace. When commodity prices fluctuate quite considerably, management considers the most updated variables available.

Discounting is carried out at 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 expected 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 asset. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segments where the asset operates. In particular, for the assets belonging to the Gas & Power segment and the Chemical business, taking into account their different risk compared with Eni as a whole, specific WACC rates have been defined on the basis of a sample of companies operating in the same segment/business, adjusted to take into consideration the risk premium of the specific country of the activity. For the other segments, 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 deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called “cash-generating unit”. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account. The reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

~~The carrying amount of property, plant and equipment is derecognized~~derecognised on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is ~~recognized~~recognised in the profit and loss account.

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Leases13 14

A contract is, or contains, a lease, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration15; such right exists whether, throughout the period of use, the customer has both the right to obtain substantially all of the economic benefits from use of the identified asset and the right to direct the use of the identified asset.

At the commencement date of the lease (i.e. the date on which the underlying asset is available for use), a lessee recognises on the balance sheet an asset representing its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability representing its obligation to make lease payments during the lease term (hereinafter also referred as lease liability).16 The lease term is the non-cancellable period of a contract, together with, if reasonably certain, periods covered by extension options or by the non-exercise of termination options.

In particular, the lease liability is initially recognised at the present value of the following lease payments17 that are not paid at the commencement date: (i) fixed payments (including in-substance fixed payments), less any lease incentives receivable; (ii) variable lease payments that depend on an index or a rate18; (iii) amounts expected to be payable by the lessee under residual value guarantees; (iv) the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and (v) payments of penalties for terminating the lease, if the lease term reflects the lessee exercising an option to terminate the lease. The lease payments are discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the lessee’s incremental borrowing rate. The latter is determined considering the term of the lease, the frequency and currency of the contractual lease payments, as well as the features of the lessee’s economic environment (reflected in the country risk premium assigned to each country where Eni operates).

After the initial recognition, the lease liability is measured on an amortised cost basis and is remeasured, normally, as an adjustment to the carrying amount of the related right-of-use asset, to reflect changes to the lease payments due, essentially, to: (i) modifications in the lease contract not accounted as a separate lease; (ii) changes in indexes or rates (used to determine the variable lease payments); or (iii) changes in the assessment of contractual options (e.g. options to purchase the underlying asset, extension or termination options).

The right-of-use asset is initially measured at cost, which comprises: (i) the amount of the initial measurement of the lease liability; (ii) any initial direct costs incurred by the lessee19; (iii) any lease payments made at or before the commencement date, less any lease incentives received; and (iv) an estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease. After the initial recognition, the right-of-use asset is adjusted for any accumulated depreciation20, any accumulated impairment losses (see the accounting policy for “Impairment of non-financial assets”) and any remeasurement of the lease liability.

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 accounting policies related to leases have been defined on the basis of IFRS 16 “Leases” effective from January 1, 2019. As allowed by the accounting standard, the new requirements have been applied without restating the comparative years. The previous accounting policies about leases required essentially that: (i) assets held under finance lease, or under arrangements that did not take the legal form of a finance lease but substantially transferred all the risks and rewards incidental to ownership of the leased asset, were recognised, at the commencement of the lease, at their fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments, within property, plant and equipment as a contra account to a financing payable to the lessor; and (ii) lease payments under an operating lease were recognised as an expense over the lease term.

As expressly provided for in IFRS 16, this accounting policy does not apply to leases to explore for and extract resources such as those for oil and gas rights, leases of land and any rights of way related to oil and gas activities.

The assessment of whether the contract is, or contains, a lease is performed at the inception date, that is the earlier of the date of a lease agreement and the date of commitment by the parties to the principal terms and conditions of the lease.

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

Eni, in accordance with the practical expedient allowed by the accounting standard, does not separate non-lease components from lease components except for main contracts related to upstream activities (drilling rigs), which provide for single payments relating to both lease and non-lease components.

Conversely, the other kinds of variable lease payments (e.g. payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability, but are recognised in the profit and loss account as operating expenses over the lease term.

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

Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee by the end of the lease term, or if the cost of the right-of-use asset reflects that the lessee will exercise a purchase option, the right-of-use asset is depreciated from the commencement date to the end of the useful life of the underlying asset.

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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 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 acquired in business combinations.~~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 ~~recognized~~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 ~~amortized~~amortised on a systematic basis over their useful ~~life estimated as the period over which the assets will be available for use by the Company;~~life; the amount to be ~~amortized~~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 ~~amortized. Their~~amortised. For the recoverability of the carrying amounts ~~are tested for impairment at least annually~~of the goodwill and ~~whenever there is any indication~~other intangible assets see the accounting policy “Impairment of ~~impairment. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management~~non-financial assets”.

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~~purposes. When~~Costs of obtaining a contract with a customer are recognised on the ~~carrying amount~~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 ~~cash-generating unit, including goodwill allocated thereto, calculated considering any~~goods or services to which the asset relates, and is tested for impairment ~~loss of the non-current assets belonging to the cash-generating unit, exceeds its recoverable amount~~1121, the excess is recognized as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the unit, up to the recoverable amount of assets with finite useful lives. An impairment loss recognized for goodwill is not reversed in a subsequent period12.

Directly attributable customer acquisition costs are capitalized when the following conditions are met: (i) the capitalized 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 revenues from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.

Costs of technological development activities are ~~capitalized~~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 ~~derecognized~~derecognised on disposal or when no future economic benefits are expected from its use or disposal; any ~~arising~~resulting gain or loss is ~~recognized~~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 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

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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(e.g. cash outflows related to forestry certificates acquired or produced consistent with the Company’s decarbonization strategy — hereinafter also forestry) are taken into account. In particular, in estimating value in use, the cash outflows for forestry projects22 are included, consistent with the medium term target of the decarbonization strategy, within the expected cash outflows of the segment whose emissions are offset. Currently, considering that the forestry projects can be developed in countries where Eni does not carry out operating activities and considering the difficulty to allocate such cash outflows, on a reasonable and consistent basis, to the CGUs of the segment, the related discounted cash outflows are treated as a reduction of the headroom of that 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 Gas & Power segment and the Chemical business, 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.23

Grants related to assets

Government grants related to assets are ~~recognized~~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 ~~realizable~~realisable value. Net ~~realizable~~realisable value is the ~~net amount expected to be realized from the sale of inventories~~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 ~~sale~~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. Materials and other supplies held for use in production are not written down below cost if the finished products in which they will be incorporated are expected to be sold at or above cost.

The cost of inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted average cost method on a three-month basis, or on a different time period (e.g. monthly), when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost of inventories of the Chemical business is determined by applying the weighted average cost on an annual basis.

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

Impairment losses recognised for goodwill in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognised in a smaller amount or would not have been recognised.

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When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations are measured using the pricing formulas contractually defined. They are ~~recognized~~recognised under “Other assets” as “Deferred costs” as a contra to “Other payables” or, after ~~the~~ settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn — the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas, within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net ~~realizable~~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 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. 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. 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.

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.

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.

~~(11)~~24

~~For~~The accounting policies related to financial instruments were defined on the ~~definition~~basis of ~~recoverable amount see~~IFRS 9 “Financial Instruments” effective from 2018; as required by the accounting ~~policy for “Property, plant and equipment”.~~

~~(12)~~

~~Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would~~standard, the new requirements have been ~~recognized in a smaller amount or would not have~~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 ~~recognized.~~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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~~Financial instruments~~

~~Current~~After initial recognition, financial assets

~~Cash~~ whose contractual terms give rise to cash flows that are solely payments of principal and ~~cash equivalents include cash~~interest on ~~hand, demand deposits, as well as~~the principal amount outstanding are measured at amortised cost if they are held within a business model whose objective is to hold financial assets ~~originally due within 90 days, readily convertible~~in order to ~~known amount of~~collect contractual cash ~~and subject~~flows (the so-called hold to ~~an insignificant risk of changes in value.~~

~~Available-for-sale~~collect business model). For financial assets ~~include~~measured at amortised cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses25 (see the accounting policy for “Impairment of financial assets”) are recognised in the profit and loss account.

Conversely, financial assets ~~other than derivative financial~~that are debt instruments ~~loans and receivables, held for trading financial assets and held-to-maturity financial assets.~~

~~Held-for-trading financial assets and available-for-sale financial assets~~ are measured at fair value ~~with gains or~~through OCI (hereinafter also FVTOCI) if they are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets (the so-called hold to collect and sell business model). In these cases: (i) interest income determined using the effective interest rate, foreign exchange differences and any impairment losses ~~recognized~~(see the accounting policy for “Impairment of financial assets”) are recognised in ~~the line item of~~ the profit and loss ~~account “Finance income (expense)” and~~account; (ii) changes in fair value of the instruments are recognised in equity, within other comprehensive income. The accumulated changes in fair value, recognised in the equity reserve13 related to other comprehensive income, ~~respectively. Changes in fair value of available-for-sale financial assets recognized in equity are charged~~is reclassified to the profit and loss account when the ~~assets are derecognized or impaired. The objective evidence that an impairment loss has occurred~~financial asset is ~~verified considering, inter alia, significant breaches of contracts, serious financial difficulties or~~derecognised. Currently the ~~risk of bankruptcy and other financial reorganization of the counterparty; impairment losses of available-for-sale financial assets are included in the carrying amount.~~

~~Interests and dividends on~~Group does not have any financial assets measured at fair value ~~are accounted~~through OCI.

A financial asset represented by a debt instrument that is neither measured at amortised cost nor at FVTOCI, is measured at fair value through profit or loss (hereinafter FVTPL); financial assets held for trading fall into this category. Interest income on ~~an accrual basis~~assets held for trading contributes to the fair value measurement of the instrument and is recognised in “Finance income (expense)”14 ~~and “Other gain (loss)~~, within “Net finance income (expense) from ~~investments”, respectively.~~ financial assets held for trading”.

When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date.

~~Receivables are measured at amortized cost (see below the accounting policy for “Non-current financial assets”).~~

~~Non-current~~Impairment of financial assets

~~Investments~~

~~Investments in equity~~The expected credit loss model is adopted for the impairment of financial assets that are debt instruments,15 but are not measured at fair value ~~with gains~~through profit or loss.

In particular, the expected credit losses ~~recognized in~~are generally measured by multiplying: (i) the ~~equity reserve related to other comprehensive income; the amounts recognized in equity are reclassified~~exposure to the ~~profit and loss account when the investment is impaired or derecognized.~~

~~When investments do not have a quoted price in an active market and their fair value cannot be reliably measured, they are measured at cost,~~counterparty’s credit risk net of any ~~impairment losses; impairment losses shall~~collateral held and other credit enhancements (Exposure At Default, EAD); (ii) the probability that the default of the counterparty occurs (Probability of Default, PD); and (iii) the percentage estimate of the exposure that will not be ~~reversed~~16recovered in case of default (Loss Given Default, LGD), considering the past experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.).

~~Receivables~~With reference to trade and ~~held-to-maturity financial assets~~other receivables, Probabilities of Default of counterparties are determined by adopting the internal credit ratings already used for credit worthiness and are periodically reviewed using, inter alia, back-testing analyses; for government entities (e.g. National Oil Companies), the Probability of Default, represented essentially by the probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for the impairment review of non-financial assets.

~~Receivables and held-to-maturity financial assets~~For customers without internal credit ratings, the expected credit losses are ~~accounted for at cost, that is~~measured by using a provision matrix, defined by grouping, where appropriate, receivables into adequate clusters to which apply expected loss rates defined on the ~~fair value~~basis of ~~the initial consideration plus transaction costs (e.g. fees, transaction costs, etc.). The initial carrying amount is then~~their historical credit loss experiences, adjusted, where appropriate, to take into account principal repayments, plus or minus the cumulative amortization of any difference between the initial amount and the maturity amount and minus any reductions for impairment or uncollectibility. Amortization is carried outforward-looking information on ~~the basis~~credit risk of the ~~effective interest rate represented by~~counterparty or clusters of counterparties.26

Considering the ~~rate that equalizes, at the moment~~characteristics of the ~~initial recognition, the present value of expected cash flows~~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 ~~the initial carrying amount (so-called “amortized cost method”). Receivables for finance leases~~be in default. Counterparties are ~~recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease.~~considered undergoing litigation when judicial/legal proceedings aimed

~~(13)~~25

~~Changes in the carrying amount of available-for-sale~~Receivables and other financial assets ~~relating to changes in foreign exchange rates~~measured at amortised cost are ~~recognized in~~presented on the ~~profit and~~balance sheet net of their loss ~~account.~~allowance.

~~(14)~~

Interests accrued on held for trading financial assets impact the total fair value measurement of the instrument and are recognized, within the line item “Finance income (expense)”, in the sub-item “Net finance income on financial assets held for trading”. Conversely, interests accrued on financial assets available-for-sale are recognized, within the line item “Finance income (expense)”, in the sub-item “Finance income”.

~~(15)~~26

For ~~investments in joint ventures~~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 ~~associates, see “The equity method~~capital needs of ~~accounting”.~~

~~(16)~~

Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized.subsidiaries.

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~~If there~~to recover a receivable have been activated or are going to be activated. Impairment losses of trade and other receivables are recognised in the profit and loss account, net of any impairment reversal, within the line item of the profit and loss account “Net (impairment losses) reversals of trade and other receivables”.

The financing receivables held for operating purposes, granted to associates and joint ventures, for which settlement is ~~objective evidence that an~~neither planned nor likely to occur in the foreseeable future and which in substance form part of the entity’s net investment in these investees, are tested for impairment, first, on the basis of the expected credit loss ~~has been incurred (see also~~model and, then, together with the carrying amount of the investment in the associate/joint venture, in accordance with the criteria indicated in the accounting policy for ~~“Current financial assets”), the impairment loss is measured as the difference between the carrying amount and the present value~~“The equity method of accounting”. In applying the expected cash flows discounted at the effective interest rate computed at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and held-to-maturity financial assets are presented net of the allowance for impairment losses; when the impairmentcredit loss ~~is definite, the allowance for impairment losses is reversed for charges, otherwise for excess. Changes~~model, any adjustments to the carrying amount of ~~receivables or~~long-term interest that arise from applying the accounting policy for “The equity method of accounting” are not taken into account.

Significant accounting estimates and judgements: impairment of financial assets

Measuring impairment losses of financial assets requires management evaluation of complex and highly uncertain elements such as, for example, Probabilities of Default of counterparties, the existence of any collateral or other credit enhancements, the expected exposure that will not be recovered in ~~accordance with~~case of default, as well as the ~~amortized~~definition of customers’ clusters to be adopted.

Investments in equity instruments

Investments in equity instruments that are not held for trading are measured at fair value through other comprehensive income, without subsequent transfer of fair value changes to profit or loss on derecognition of these investments; conversely, dividends from these investments are recognised in the profit and loss account, within the line item “Income (Expense) from investments”, unless they clearly represent a recovery of part of the cost ~~method are recognized as “Finance income (expense)”.~~of the investment. In limited circumstances, an investment in equity instruments can be measured at cost if it is an appropriate estimate of fair value.

Financial liabilities

~~Financial~~At initial recognition, financial liabilities, other than derivative financial instruments, are measured at ~~amortized cost (see above the accounting policy for “Non-current financial assets”).~~their fair value, minus transaction costs that are directly attributable, and are subsequently measured at amortised cost.

Derivative financial instruments and hedge accounting

Derivative financial instruments, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value.

~~Derivatives are designated as~~With reference to the defined risk management objectives and strategy, the qualifying criteria for hedge accounting requires: (i) the existence of an economic relationship between the hedged item and the hedging ~~instruments when~~instrument in order to offset the related value changes and the effects of counterparty credit risk do not dominate the economic relationship between the hedged item and the hedging instrument; and (ii) the definition of the relationship between the ~~derivative and~~quantity of the hedged item ~~is formally documented~~ and the quantity of the hedging instrument (the so-called hedge ratio) consistent with the entity’s risk management objectives, under a defined risk management strategy; the hedge ratio is ~~regarded as highly effective and reviewed~~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 ~~an ongoing basis.~~ 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 ~~item~~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 ~~item~~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 ~~that are designated as effective hedging instruments,~~ are initially ~~recognized~~recognised in the equity reserve

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related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account.

If a hedged forecast transaction subsequently results in the recognition of a non-financial asset or a non-financial liability, the accumulated changes in fair value of hedging derivatives, recognised in equity, are included directly in the carrying amount of the hedged non-financial asset/liability (commonly referred to as a “basis adjustment”).

The changes in the fair value of derivatives that are not designated as ~~effective~~ hedging instruments, including any ineffective portion of changes in fair value of hedging derivatives, are ~~recognized~~recognised in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are ~~recognized~~recognised in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are ~~recognized~~recognised in the profit and loss account line item “Other operating (expense) income”.

~~Embedded derivatives~~ Derivatives embedded in financial assets are not accounted for separately; in such circumstances, the entire hybrid ~~instruments~~instrument is classified depending on the contractual cash flow characteristics of the financial instrument and the business model for managing it (see the accounting policy for “Financial assets”). Derivatives embedded in financial liabilities and/or non-financial assets are separated ~~from the host contract and accounted for as a derivative if the hybrid instruments are not measured at fair value with changes in fair value recognized in the profit and loss account and if~~if: (i) the economic characteristics and risks of the embedded ~~derivatives~~derivative are not closely related to ~~those~~the economic characteristics and risks of the host ~~contracts. The entity~~contract; (ii) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and (iii) the entire hybrid contract is not measured at FVTPL.

Eni assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows occurs.

Contracts to buy or sell commodities entered into and ~~continue~~continued to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are ~~recognized~~recognised on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

Offsetting of financial assets and liabilities

Financial assets and liabilities are set off inon the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to ~~realize~~realise the asset and settle the liability simultaneously).

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Derecognition of financial assets and liabilities

Transferred financial assets are ~~derecognized~~derecognised when the contractual rights to receive the cash flows from the financial assets expire or are ~~realized, expired or transferred.~~transferred to another party. Financial liabilities are ~~derecognized~~derecognised when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired.

Cash and cash equivalents

Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due, generally, within 90 days, readily convertible to known amount of cash and subject to an insignificant risk of changes in value.

Provisions, contingent ~~assets~~liabilities and ~~liabilities~~contingent assets

A provision is a liability of uncertain timing or amount aton the balance sheet date. Provisions are ~~recognized~~recognised when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. The amount ~~recognized~~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 ~~recognized~~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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are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is ~~recognized~~recognised as “Finance income (expense)”.

Where an obligation exists for an item of property, plant and equipment (e.g. site dismantling and restoration), the provision is recognized together with a corresponding amount as part of the related item of property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset.

A provision for restructuring costs is ~~recognized~~recognised only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring.

Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are ~~recognized~~recognised in the same profit and loss account line item where the original provision was charged, or, when the liability regards tangible assets (e.g. site dismantling and restoration), changes in the provision are recognized with a corresponding entry to the assets to which they refer, to the extent of the assets’ carrying amounts; any excess amount is recognized in the profit and loss account.charged.

Contingent liabilities ~~are disclosed as follows:~~are: (i) possible ~~but not probable~~ obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent liabilities are not recognised in the financial statements, but are disclosed.

Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not ~~recognized~~recognised unless the ~~realization~~realisation of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable.

Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements; if it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are ~~recognized~~recognised in the financial statements of the period in which the change occurs.

Decommissioning and restoration liabilities

Liabilities for decommissioning and restoration costs are recognized, together with a corresponding amount as part of the related property, plant and equipment, when the Group has a legal or constructive obligation and when a reliable estimate can be made.27

Considering the long time span between the recognition of the obligation and its settlement, the amount recognised is the present value of the future expenditures expected to be required to settle the obligation. The increase in the provision due to the unwinding of the discount is recognised as “Finance income (expense)”.

Such liabilities are reviewed regularly to take into account the changes in the expected costs to be incurred, contractual obligations, regulatory requirements and practices in force in the countries where the tangible assets are located.

The effects of any changes in the estimate of the liability are recognised generally as an adjustment to the carrying amount of the related property, plant and equipment; however, if the resulting decrease in the liability exceeds the carrying amount of the related asset, the excess is recognised in the profit and loss account.

Significant accounting estimates and judgements: decommissioning and restoration liabilities, environmental liabilities and other provisions

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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to make estimates and judgements with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations.

The discount rate used to determine the provision and the timing of future cash outflows, as well as any related update, are based on complex managerial judgements.

As other oil and gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental liabilities are recognised when it becomes probable that an outflow of resources will be required to settle the obligation and such obligation can be reliably estimated.28

Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provisions already recognised, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.

In addition to environmental and decommissioning and restoration liabilities, Eni recognises provisions primarily related to legal and trade proceedings. These provisions are estimated on the basis of complex managerial judgements related to the amounts to be recognised and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate.

Employee benefits

Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment.

Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. Under defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due.

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The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits.

Net interest includes the return on plan assets and the ~~interests~~interest cost to be ~~recognized~~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 ~~recognized~~recognised in “Finance income (expense)”.

~~Re-measurements~~Remeasurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are ~~recognized~~recognised within the statement of comprehensive income. ~~Re-measurements~~Remeasurements of the net defined benefit liability, ~~recognized in the equity reserve related to~~recognised within other comprehensive income, are not reclassified subsequently to the profit and loss ~~account~~account.

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 ~~subsequent period.~~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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Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of ~~re-measurements~~remeasurements are taken to profit and loss account in their entirety.

Share-based payments

The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistent with its actual remunerative nature.29 The cost of the share-based incentive plan is measured by reference to the fair value of the equity instruments granted and the estimate of the number of shares that eventually vest; the cost is recognised on an accrual basis pro rata temporis over the vesting period, that is the period between the grant date and the settlement date. The fair value of the shares underlying the incentive plan is measured at the grant date, taking into account the estimate of achievement of market conditions (e.g. Total Shareholder Return), and is not adjusted in subsequent periods; when the achievement is linked also to non-market conditions, the number of shares expected to vest is adjusted during the vesting period to reflect the updated estimate of these conditions. If, at the end of the vesting period, the incentive plan does not vest because of failure to satisfy the performance conditions, the portion of cost related to market conditions is not reversed to the profit and loss account.

Significant accounting estimates and judgements: employee benefits and share-based payments

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates are based on the market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds) and on the expected inflation rates in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilisation, changes in health status of the participants and the contributions paid to health funds; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved.

Differences in the amount of the net defined benefit liability (asset), deriving from the remeasurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Similar to the approach followed for the fair value measurement of financial instruments, the fair value of the shares underlying the incentive plans is measured by using complex valuation techniques and identifying, through structured judgements, the assumptions to be adopted.

Treasury shares

Treasury shares, including shares held to meet the future requirements of the share-based incentive plans, are ~~recognized~~recognised as deductions from equity at cost. Any gain or loss resulting from subsequent sales is ~~recognized~~recognised in equity.

~~Revenues~~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 ~~costs~~

~~Revenues from the sale of products and the rendering of services are recognized~~(v) recognising revenue when ~~the significant risks and rewards of ownership have been~~(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 ~~or when the transaction~~obtains control of it. Control can be ~~considered~~transferred over time or at a

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

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point in time. With reference to the most important products sold by Eni, revenue ~~can be reliably measured. In particular, revenues are recognized for the sale of:~~is generally recognised for:

•

crude oil, ~~generally~~ upon shipment;

•

natural gas and electricity, upon delivery to the customer;

•

petroleum products sold to retail distribution networks, ~~generally~~ upon delivery to the service stations, whereas all other sales of petroleum products are ~~generally recognized~~recognised upon shipment; and

•

chemical products and other products, ~~generally~~ upon shipment.

~~Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer.~~

~~Revenues~~Revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers ~~are recognized~~is recognised on the basis of ~~Eni’s net working interest in those properties (entitlement~~the quantities actually lifted and sold (sales method)~~. Higher/lower production volume withdrawn as compared to Eni’s net working interest volume is recognized at current prices at~~; costs are recognised on the ~~balance sheet date.~~

~~Revenues arising from rendering of services are recognized by reference to the stage of completion at the end~~basis of the ~~reporting period, provided that: (i) the amount of revenues can be measured reliably; (ii) it~~quantities actually sold.30

Revenue is probable that the economic benefits associated with the transaction will flow to the entity; (iii) the stage of completion of the transaction at the end of the reporting period can be measured reliably; and (iv) the related costs can be measured reliably. When the outcome of the transaction involving the rendering of services cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable.

~~Revenues are~~ measured at the fair value of the consideration ~~received or receivable net of returns, discounts, rebates, bonuses and related taxes. Amounts collected or~~to which the Company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third ~~parties are not revenues.~~

~~Award credits, related to customer loyalty programs, are recognized as a separately identifiable component~~parties. In determining the transaction price, the promised amount of consideration is adjusted for the effects of the ~~sales transaction in which they are granted. Therefore,~~time value of money if the timing of payments agreed to by the parties to the contract provides the customer or the entity with a significant benefit of financing the transfer of goods or services to the customer. The promised amount of consideration is not adjusted for the effect of the significant financing component if, at contract inception, it is expected that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. If the consideration ~~allocated~~promised in a contract includes a variable amount, the Company estimates the amount of consideration to which it will be entitled in exchange for transferring the promised goods and/or services to a customer; in particular, the amount of consideration can vary because of discounts, refunds, incentives, price concessions, performance bonuses, penalties or if the price is contingent on the occurrence or non-occurrence of future events.

If, in a contract, the Company grants a customer the option to acquire additional goods or services for free or at a discount (e.g. sales incentives, customer award points, etc.), this option gives rise to a separate performance obligation in the contract only if the option provides a material right to the ~~award credits, measured by reference to their fair value, represents deferred revenues and~~customer that it ~~is recognized in~~

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~~the line item “Other liabilities”. The deferred revenues are reversed in the profit and loss account at the redemption or forfeiture of the award credits by customers.~~would not receive without entering into that contract. When goods or services are exchanged for goods or services ~~that~~which are of a similar nature and value, the exchange is not regarded as a transaction which generates revenue.

Significant accounting estimates and judgements: revenue from contracts with customers

Revenue from sales of electricity and gas to retail customers includes 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 ~~revenue.~~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.

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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Costs

Costs are ~~recognized~~recognised when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) determined on the basis of ~~the~~ market prices, are ~~recognized~~recognised in relation to the ~~amount~~amounts of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights that exceed the amount necessary to meet regulatory obligations are ~~recognized~~recognised as intangible ~~assets net of any imbalance between the amount of actual emissions and the free allowances. Revenues~~assets. Revenue related to emission quotas ~~are recognized~~is recognised when they are ~~sold and, if applicable, purchased emission rights are considered the first to be~~ sold. Monetary receivables granted to replace the free award emission rights are ~~recognized~~recognised as a contra to the line item “Other income and revenues”. The costs incurred on a voluntary basis for the acquisition or production of forestry certificates, also taking into account the absence of an active market, are recognised in the profit and loss account when incurred.

~~Operating lease payments are recognized as an expense over the lease term.~~ The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be ~~capitalized~~capitalised (see ~~above~~also the accounting policy for “Intangible assets”), are included in the profit and loss account when they are ~~incurred.~~

~~Grants not related to assets are recognized in the profit and loss account on an accrual basis matching the related costs when~~ incurred.

Exchange differences

Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss ~~account.~~account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognised. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net ~~realizable~~realisable value are retranslated using the exchange rate at the date when the value is determined.

Dividends

Dividends are ~~recognized at~~recognised when the ~~date~~right to receive payment of the ~~general~~dividend is established.

Dividends and interim dividends to owners are shown as changes in equity when the dividends are declared by, respectively, the shareholders’ meeting ~~in which they were declared, except when~~and the ~~sale~~Board of ~~shares before the ex-dividend date is certain.~~Directors.

Income taxes

Current income taxes are determined on the basis of estimated taxable ~~income. The estimated liability is included in “Income taxes payable”.~~profit. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period.

Deferred tax assets and liabilities are ~~recognized~~recognised for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted ~~for future years.~~by the end of the reporting period. Deferred tax assets are ~~recognized~~recognised when their recoverability is considered ~~probable; in particular, deferred tax assets are recoverable~~probable, i.e. when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are ~~recognized~~recognised to the extent that their recoverability is probable. ~~Income~~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 ~~are~~the taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognised in the ~~amount~~ financial statements consistent with the tax treatment used or planned

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to be ~~recovered are recognized~~used in ~~accordance~~its income tax filings. Conversely, if the company concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognised in the ~~probable threshold.~~financial statements.

Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not ~~recognized~~recognised if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets and liabilities are

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~~included in~~ presented within non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is ~~recognized~~recognised in the line item “Deferred tax assets”; and, if negative, in the line item “Deferred tax liabilities”. When the results of transactions are ~~recognized~~recognised directly in shareholders’ equity, the related current and deferred taxes are also charged to the shareholders’ equity.

Significant accounting estimates and judgements: income taxes

The computation of income taxes involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. Although Eni aims to maintain a relationship with the taxation authorities characterised by transparency, dialogue and cooperation (e.g. by not using aggressive tax planning and by using, if available, procedures intended to eliminate or reduce tax litigations), there can be no assurance that there will not be a tax litigation with the taxation authorities where the legislation could be open to more than one interpretation. The resolution of tax disputes, through negotiations with relevant taxation authorities or through litigation, could take several years to complete. The estimate of liabilities related to uncertain tax treatments requires complex judgements by management. After the initial recognition, these liabilities are periodically reviewed for any changes in facts and circumstances.

Moreover, management makes complex judgements regarding the assessment of the recoverability of deferred tax assets, related both to deductible temporary differences and unused tax losses, which requires estimates and evaluations about the amount and the timing of future taxable profits.

Assets held for sale and discontinued operations

Non-current assets and current and non-current assets included within disposal groups, are classified as held for sale if their carrying ~~amount~~amounts will be recovered principally through a sale transaction rather than through their continuing use. ~~For this to be the case,~~This condition is regarded as met only when the sale ~~must be~~is highly probable and the asset or the disposal group ~~must be~~is available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale. The classification of non-current assets (or disposal groups) as held for sale requires the management to perform subjective judgments based on assumptions deemed reasonable in consideration of the information available at the time.

Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are ~~recognized in~~recognised on the balance sheet separately from other assets and liabilities.

Immediately before the initial classification of a non-current asset and/or a disposal group as held for sale, the non-current asset and/or the assets and liabilities ofin the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated or amortised and they are measured at the lower of the fair value less costs to sell and their carrying amount. ~~After the classification as held for sale of~~If an equity-accounted investment, ~~the investment,~~ or ~~the~~a portion of ~~the~~that investment ~~that~~ meets the criteria to be classified as held for sale, it is no longer accounted for using the equity ~~method; therefore, in this case,~~method and it is measured at the lower of its carrying amount ofat the ~~investment in accordance with~~date the equity method ~~represents the carrying amount for the measurement as non-current asset held for sale.~~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, ~~takes place,~~ any retained ~~investment~~interest in the investee is measured in accordance with the measurement criteria indicated in the accounting policy for ~~“Non-current financial assets — Investments”~~“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 ~~recognized~~recognised up to the cumulative impairment losses, including those ~~recognized~~recognised prior to qualification of the asset as held

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for sale. Non-current assets ~~and current and non-current assets included within disposal groups,~~ classified as held for sale and disposal groups are considered a discontinued operation if they, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss ~~recognized~~recognised on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements.

If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, ~~amortisations,~~amortisation impairment losses and reversals that would have been ~~recognized~~recognised had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell. If the interruption of a plan of sale concerns a subsidiary, joint operation, joint venture, associate, or a portion of an interest in a joint venture or an associate, financial statements for the period since classification as held for sale are amended.

If a discontinued operation is reclassified as held for use, its results previously presented in the separate line item of the profit and loss account are reclassified and included in income from continuing operations for all periods presented.

Fair value measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement

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date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured.

A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would ~~maximize~~maximise the value of the asset.

The fair value of a liability, both financial and non-financial, or of athe Company’s own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty’s credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the ~~entity’s~~Company’s own credit risk for a financial liability (Debit Valuation Adjustment, DVA).

In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, ~~maximizing~~maximising the use of relevant observable inputs and ~~minimizing~~minimising the use of unobservable inputs.

~~4 Financial~~Significant accounting estimates and judgements: fair value

Fair value measurement, although based on the best available information and on the use of appropriate valuation techniques, is inherently uncertain, requires the use of professional judgement and could result in expected values other than the actual ones.

2 Primary financial statements1731

Assets and liabilities on the balance sheet are classified as current and non-current. Items onin the profit and loss account are presented by ~~nature~~nature.1832. Assets and liabilities are classified as current when: (i) they are expected to be ~~realized/~~realised/settled in the entity’s normal operating cycle or within twelve months after the

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.

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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balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be ~~realized/~~realised/settled within twelve months after the balance sheet date; on the contrary they are classified as non-current.

The statement of comprehensive income (loss) shows net profit integrated with income and expenses that are ~~recognized~~not recognised directly in ~~equity~~the profit and loss account according to ~~IFRS.~~IFRSs.

The statement of changes in shareholders’ equity includes the total comprehensive income (loss) for the year, transactions with shareholders in their capacity as shareholders and other changes in shareholders’ equity.

The statement of cash flows is presented using the indirect method, whereby net profit (loss) is adjusted for the effects of non-cash transactions.

53 Changes in accounting policies

~~In accordance with IAS 8 “Accounting Policies, Changes in Accounting Estimates and Errors”, the adoption of SEM represents a voluntary change in accounting policies, in order to increase the~~

~~(17)~~

The financial statements are the same presented in the last Annual Report on Form 20-F, with the exception of: (i) the profit and loss account and the statement of cash flows that include the new line item “Write-off” which presents the loss from the derecognition of property, plant and equipment or intangible assets. The presentation of this new line item is regarded as relevant by management due to the adoption, on a voluntary basis, of the recognition and measurement criteria for the costs related to the oil and gas activities in accordance with the Successful Efforts Method (SEM), as described in note 5 “Changes in accounting policies”; (ii) the profit and loss account that include the new line item “Net impairment losses (reversals)”, which includes the net balance of impairment losses/reversals of tangible and intangible assets. The presentation of this new line item is regarded as relevant by management in order to avoid that the compensation between depreciations/amortizations and net impairment reversals would provide a misleading representation to users of financial statements.

~~(18)~~

~~Further information on financial instruments as classified in accordance with IFRS is provided in note 38 - Guarantees, commitments and risks — Other information about financial instruments.~~

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comparability with the companies operating in the same industry and provide a reliable and more relevant financial information. SEM has been applied retrospectively; therefore, comparative amounts have been restated. Under the previous accounting policy: (i) the costs for the acquisition of exploration rights were amortized on a straight-line basis over the exploration period as contractually established; (ii) the costs associated with exploration activities were initially capitalized, in order to reflect their nature as capital expenditure, and fully amortized as incurred.

Furthermore, because of the withdrawal of Versalis sale plan, the criteria for its classification as disposal group and discontinued operations are no longer met; therefore the 2014 and 2015 comparative figures have been amended as if Versalis had never been classified as held for sale. The financial statements line items affected by the above-mentioned changes are presented below.

(€ million) January 1, 2014
Selected line items only As reported Adoption of
the SEM As restated
Non-current assets 85,584 4,085 89,669
- of which property, plant and equipment 63,763 3,524 67,287
- of which intagible assets 3,876 860 4,736
Non-current liabilities 44,283 1,081 45,364
Total Shareholders’ Equity 61,049 3,004 64,053
(€ million) January 1, 2015
Selected line items only As reported Adoption of
the SEM As restated
Non-current assets 91,344 4,159 95,503
- of which property, plant and equipment 71,962 4,029 75,991
- of which intagible assets 3,645 775 4,420
Non-current liabilities 46,659 727 47,386
Total Shareholders’ Equity 62,209 3,432 65,641

(€ million) December 31, 2015
Selected line items only As reported Restatement
of Versalis in
continuing
operations Adoption of
the SEM As restated
Current assets 39,982 1,388 41,370
Non-current assets 77,294 889 3,915 82,098
- of which property, plant and equipment 63,795 323 3,887 68,005
- of which intagible assets 2,433 55 546 3,034
Discontinued operations and assets held for sale 17,516 (1,983) 15,533
Current liabilities 29,565 370 29,935
Non-current liabilities 44,488 215 469 45,172
Discontinued operations and liabilities directly associated with assets held for sale 7,070 (585) 6,485
Total Shareholders’ Equity 53,669 294 3,446 57,409

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(€ million) 2014
Selected line items only As reported Restatement
of Versalis in
continuing
operations Adoption of
the SEM As restated
Revenue 94,226 5,078 (7) 99,297
Operating expense 73,930 3,106 368 77,404
Depreciation, amortization 9,134 99 (1,557) 7,676
Net impairment (reversal) 1,013 96 161 1,270
Write-off of tangible and intangible assets 137 1 1,060 1,198
Operating profit (loss) 7,585 1,419 (39) 8,965
Finance income and expense (1,181) 14 (1,167)
Income (expense) from investments 469 (3) 10 476
Income taxes 6,681 (191) (24) 6,466
Net profit – continuing operations 192 1,607 9 1,808
Net profit – discontinued operations 658 (1,607) (949)
Net profit 850 9 859
Net profit attributable to Eni 1,291 12 1,303
- attributable to Eni in continuing operations 101 1,607 12 1,720
- attributable to Eni in discontinued operations 1,190 (1,607) (417)
Net cash provided by operating activities 15,110 (368) 14,742
Net cash used in investing activities (8,943) 368 (8,575)
Net cash used in financing activities (5,062) (5,062)
Net cash flow for the period 1,183 1,183

(€ million) 2015
Selected line items only As reported Restatement
of Versalis in
continuing
operations Adoption of
the SEM As restated
Revenue 68,945 4,603 (10) 73,538
Operating expense 53,958 2,636 254 56,848
Depreciation, amortization 9,654 108 (822) 8,940
Net impairment (reversal) 4,826 998 710 6,534
Write-off of tangible and intangible assets 25 663 688
Operating profit (loss) (2,781) 520 (815) (3,076)
Finance income and expense (1,323) 3 14 (1,306)
Income (expense) from investments 124 (20) 1 105
Income taxes 3,147 486 (511) 3,122
Net profit - continuing operations (7,127) 17 (289) (7,399)
Net profit - discontinued operations (2,251) 277 (1,974)
Net profit (9,378) 294 (289) (9,373)
Net profit attributable to Eni (8,783) 294 (289) (8,778)
- attributable to Eni in continuing operations (7,680) 17 (289) (7,952)
- attributable to Eni in discontinued operations (1,103) 277 (826)
Net cash provided by operating activities 11,903 (254) 11,649
Net cash used in investing activities (11,177) 254 (10,923)
Net cash used in financing activities (1,351) (1,351)
Net cash flow for the period (1,414) 9 (1,405)

~~The amendments to IFRSs effective~~Starting from January 1, ~~2016 did not have a significant impact on the financial statements.~~

~~6 Significant accounting estimates or judgements~~

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognized in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and

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areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, employee benefits and recognition of environmental liabilities. Although the Company uses its best estimates and judgments, 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.

~~Oil and natural gas activities~~

Engineering estimates of the Company’s oil&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&gas reserves can be categorized as “proved”, the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgment.

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 expenditure required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such carried costs are reviewed on at least an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery.

Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production.2019, Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision. Upward or downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion charges and impairment charges. Depreciation and depletion rates of oil&gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation and depletion charge. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion charge. Estimated proved reserves are affected, inter alia, by the trend of reference oil and gas commodity prices and by the specific legal agreement for the oil&gas activity.

In addition, estimated proved reserves are used to calculate future cash flows from oil&gas properties, which are used to assess any impairment loss. The larger is the volume of estimated reserves, the lower is the likelihood of asset impairment.

~~Impairment of assets~~

~~Assets are impaired when there are events or changes in circumstances that indicate that carrying amounts of the assets are not recoverable. Such impairment indicators include changes in the Group’s~~

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business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilization of plants and, for oil&gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development 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, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for demand and supply conditions on a global or regional scale. Similar remarks are valid for assessing the physical recoverability of assets recognized in 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, as well as for assessing the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the carrying amount of an asset with its recoverable amount. Recoverable amount of an asset is the higher of an asset’s fair value less costs of disposal and its value in use. The estimate of an asset’s value in use is based on the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reasonably determinable, the cash flows expected to be obtained from the disposal of the asset at the end of its useful life after deducting the costs of disposal. The expected future cash flows used for impairment analyses are based on judgmental 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. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil&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 specialized analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows.

Goodwill and intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets on an annual basis and whenever there is any indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash-generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash-generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash-generating unit, to which goodwill has been allocated, is less than its carrying amount, goodwill allocated to that cash-generating unit is impaired up to that difference; if the carrying amount of goodwill is lower than the amount of the impairment loss, the other assets of the cash-generating unit are impaired pro-rata on the basis of their carrying amounts for the residual difference, up to the recoverable amount of assets with finite useful lives.

~~Decommissioning and restoration liabilities~~

The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The complexity of these estimates is also due to the accounting that requires the initial recognition of the present value of the decommissioning and restoration liabilities as a part of the cost of property, plant and equipment. Then the carrying amount of decommissioning and restoration liabilities is adjusted to reflect the passage of time and any change in the estimates following the modification of amount and timing of future cash flows and discount rates adopted. The discount rate used to determine the provision is based on complex and subjective managerial judgments.

~~Business combinations~~

Accounting for business combinations requires the allocation of the purchase price to the identifiable assets and liabilities of the acquired business generally at their fair values. Any positive residual difference is

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recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date are 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. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors; the purchase price allocation, that requires, also in consideration of the available information, management to make complex judgments, is also relevant for the application of the equity method.

~~Environmental liabilities~~

As other oil&gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil&gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental provisions are recognized when it becomes probable that a liability will be incurred and the liability can be reliably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.

~~Employee benefits~~

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds). The inflation rates reflect market conditions observed in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved.

Differences in the amount of the net defined benefit liability (asset), deriving from the re-measurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Re-measurements are recognized within statement of comprehensive income for defined benefit plans and within the profit and loss account for long-term plans.

~~Other provisions~~

In addition to liabilities related to environmental decommissioning and restoration liabilities and employee benefits, Eni recognizes provisions primarily related to legal and tax proceedings. These provisions are estimated on the basis of managerial judgments related to the amounts to recognize and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate.

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~~Revenues and receivables~~

Revenues from the sale of electricity and gas to retail customers include amount accrued for electricity and gas supplied between the date of the last meter reading and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as they rely on other factors, considered by management, which can impact on them. Therefore accrued revenues derive from complex estimates based on distributed and allocated volumes, communicated by third parties; these revenues may be adjusted, according to the applicable regulations, within the fifth year subsequent the one in which they were accrued.

Complex and/or subjective judgements are required in assessing the recoverability of overdue receivables and determining whether an allowance against those receivables is required. Factors considered include, among others, the credit rating of the counterparty (if available), the amount and timing of anticipated future payments, any collateral held as a security and other credit enhancements, as well as any possible actions that can be taken to mitigate the risk of non-payment.

~~7 IFRSs not yet adopted~~

On May 28, 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” (hereinafter IFRS 15), which sets out the requirements for recognizing and measuring revenues arising from contracts with customers, including construction contracts. In particular, IFRS 15 requires that, to recognize revenue, a company shall apply the following five steps: (i) identify the contract with the customer; (ii) identify the performance obligations (that are promises in a contract to transfer to a customer goods and/or services); (iii) determine the transaction price; (iv) allocate the transaction price to each performance obligation on the basis of the relative standalone selling prices of each good or service promised in the contract; and (v) recognize revenue when a performance obligation is satisfied. Moreover, IFRS 15 includes more disclosure requirements about the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. IFRS 15 shall be applied for annual periods beginning on or after January 1, 2018; IFRS 15 shall be applied retrospectively, by providing for the possibility of recognizing the cumulative effect of initially applying IFRS 15 as an adjustment to the opening balance of equity as January 1, 2018, having regard only to the contracts that are not completed at the date of initial application. Furthermore, on April 12, 2016, the IASB issued the document “Clarifications to IFRS 15 Revenue from Contracts with Customers” (hereinafter clarifications to IFRS 15), which provides clarifications to support implementation of the new standard. The clarifications to IFRS 15 shall be applied for annual periods beginning on or after January 1, 2018.

In 2016, the Group started analytical activities aimed to identify potentially critical issues for each operating segment, to assess the potential effects on the financial statements and verify the need to adjust internal control system over financial reporting. At the current stage of the analysis, the following areas may be affected by the new provisions of the standard: (i) accounting for certain types of agreements with partners within oil&gas projects, considering their different nature from customers; (ii) representation on a gross or net basis of certain types of costs closely related to supplying of goods or services; (iii) multiple-element arrangements; (iv) capitalization of the customer acquisition costs principally in the Gas & Power segment; (v) contracts with options to acquire additional goods/services that provide a material right that customers would not receive without entering into the contracts; (vi) contracts with variable consideration; (vii) licenses of intellectual property principally in the Refining & Marketing and Chemical segment.

On July 24, 2014, the IASB completed its project to replace IAS 39 by issuing the final version of IFRS 9 “Financial Instruments” (hereinafter IFRS 9). In particular, IFRS 9: (i) changes the classification and measurement approach for financial assets, basing it on the characteristics of the financial instrument and on the business model adopted by the entity for managing it; (ii) introduces a new impairment model for financial assets, which considers the expected credit losses; and (iii) includes an improved hedge accounting model. IFRS 9 shall be applied for annual periods beginning on or after January 1, 2018.

In 2016, the Group started analytical activities with reference to the three main updated areas above-mentioned. In particular, the Group is assessing if the new classification requirements of IFRS 9 will impact the current way of classification of financial instruments; at the current stage of the analysis, the Group has not identified relevant impacts. An in-depth analysis on the fair value measurements of minority

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~~investments in equity instruments that, under current provisions, are measured at cost when their fair value cannot be reliably measured, is being carried out.~~

With reference to the application of the expected credit loss model, the ongoing activities essentially concern: (i) for counterparties with an identifiable credit risk factor (e.g. the credit rating), the adoption of the expected loss model, defined having regard also to the current credit enhancements held (e.g. collaterals, guarantees, insurance contracts, etc.); (ii) for retail customers, the implementation of provision matrix to represent adequately the credit standing of the counterparty; and (iii) the revision and optimization of the operating processes to ensure the availability of information for implementing the evaluation models and drawing up the financial reporting.

In relation to hedge accounting, analyses on the applicability of the new qualifying criteria provided by IFRS 9 and on the implementation of rebalancing mechanism to maintain a hedge ratio that complies with the hedge effectiveness requirements, is being carried out.

~~At the current stage of the analyses, the likely impacts deriving from the application of the new IFRS 15 and IFRS 9 are not yet reasonably estimable.~~

On September 11, 2014, the IASB issued the amendments to IFRS 10 and IAS 28 “Sale or Contribution of Assets between an Investor and its Associate or Joint Venture” (hereinafter the amendments to IFRS 10 and IAS 28), which define the recognition criteria of the economic effects mainly related to the loss of control of an investment as a consequence of its transfer to an associate or a joint venture. On December 17, 2015, the IASB issued an amendment that postpones the application of the amendments to IFRS 10 and IAS 28 indefinitely.

~~On January 13, 2016, the IASB issued~~ IFRS 16 ~~“Leases”~~ (hereinafter IFRS 16), which replaces IAS 17 and related interpretations. In particular, IFRS 16 ~~defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration. The new IFRS~~ eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial ~~statements; for all leases with a term of more than 12 months, the lessee shall recognize an asset, as the right-of-use, and a liability, as the present value of the lease payments.~~statements. Conversely, a lessor continues to classify its leases as either operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and ~~for~~ lessors. ~~IFRS 16 shall be applied for annual periods beginning on or after~~

With reference to the lessee’s primary financial statements, starting from January 1, ~~2019.~~2019:

~~On January 19, 2016,~~-

on the ~~IASB issued~~balance sheet, right-of-use assets and lease liabilities are recognised and presented separately from other assets and other liabilities;

in the ~~amendments~~profit and loss account, depreciation charges and any impairment losses/write-offs of the right-of-use asset are recognised within operating expenses and the interest expense on the lease liability, if not capitalised, is recognised within finance expense rather than recognising the operating lease payments within operating expenses under IAS 17. The depreciation charges of the right-of-use asset and the interest expenses on the lease liability directly attributable to ~~IAS 12 “Recognition of Deferred Tax Assets for Unrealized Losses”, which provide clarifications about~~ the ~~recognition and measurement of deferred tax assets. The amendments to IAS 12 shall be applied for annual periods beginning on or after January 1, 2017.~~

On January 29, 2016, the IASB issued the amendments to IAS 7 “Disclosure Initiative”, which enhance disclosures required in case of changes in liabilities arising from financing activities, including both changes arising from cash flows and non-cash changes. The amendments to IAS 7 shall be applied for annual periods beginning on or after January 1, 2017.

On December 8, 2016, the IASB issued the IFRIC Interpretation 22 “Foreign Currency Transactions and Advance Consideration” (hereinafter IFRIC 22), which sets out that the exchange rate to use on initial recognitionconstruction of an asset are capitalised as part of the cost of such asset and subsequently recognised in the profit and loss account through depreciation/impairments or write-off, mainly in the case of exploration assets. Moreover, the profit and loss account includes: (i) the expenses relating to short-term leases and low-value leases; (ii) the expenses relating to variable lease payments that are not included in the measurement of the lease liability (e.g. payments that depend on the use of the underlying asset); and (iii) the expenses relating to any non-lease components accounted for separately from the lease component;

in the statement of cash flows, cash payments for the principal portion of the lease liability are classified within financing activities, whereas interest expense is classified within operating activities, if they are recognised in the profit and loss account, or ~~income~~within investing activities if they are capitalised in reference to leased assets that are used for the construction of other assets.33 Consequently, compared to the requirements of IAS 17 related to operating leases, the adoption of IFRS 16 has a significant impact in the statement of cash flows, by determining: (a) an ~~advance consideration, previously paid or received in a foreign currency, is the rate used at the date of initial recognition~~improvement of the ~~non-monetary asset or non-monetary~~net cash provided by operating activities, which no longer includes operating lease payments, not capitalised, but only includes the cash payments for the interest portion of the lease liability ~~arising from~~that are not capitalised34; (b) an improvement of the ~~payment or receipt~~net cash used in investing activities, which no longer includes capitalised lease payments, but only includes cash payments for the capitalised interest portion of ~~that advance consideration. The IFRIC 22 shall be applied~~the lease liability; and (c) a worsening in the net cash used in financing activities, which includes cash payments for ~~annual periods beginning on or after January 1, 2018.~~the principal portion of the lease liability.

On December 8, 2016, the IASB issued the document “Annual Improvements to IFRS Standards 2014-2016 Cycle”, which include, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual periods beginning on or after January 1, 201819.

~~Eni is currently reviewing these new IFRSs to determine the likely impact on the Group’s results.~~

~~(19)~~33

The ~~clarification~~prepayments for right-of-use assets, made before the commencement date of lease contracts, are classified within investing activities.

The net cash provided by operating activities will include also: (i) short-term lease payments and payments for low-value leases; (ii) variable lease payments not included in the ~~scope~~measurement of ~~the IFRS 12 “Disclosure of Interests in Other Entities” shall be applied~~lease liabilities; and (iii) payments for ~~annual periods beginning on or after January 1, 2017.~~non-lease components.

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The adoption of the new requirements affects most of the Group companies; in terms of amounts and/or volumes, the main cases are the following: (i) in the Exploration & Production segment, contracts for the lease of drilling rigs and floating production storage and offloading vessels (the so-called FPSOs); (ii) in the Refining & Marketing and Chemical segment, highway concessions, leases of land, service stations for the sale of oil products, as well as the car fleet dedicated to the car sharing business (enjoy); (iii) in the Gas & Power segment, leases of vessels used for shipping activities and gas distribution facilities, as well as tolling contracts; (iv) for Corporate activities, leases of property.

IFRS 16 has been applied, starting from January 1, 2019, by recognising, as allowed by the transition requirements of the accounting standard, the cumulative effect of the initial application as an adjustment to the opening balance of equity at January 1, 2019, with no restatement of comparative information (the so-called modified retrospective approach). In particular, the adoption of IFRS 16 resulted in the recognition of right-of-use assets for €5.7 billion and lease liabilities for €5.8 billion; the amount of the lease liabilities includes also the payables for lease fees outstanding at January 1, 2019, previously classified as trade payables. Such impacts take into account the indications of the IFRS Interpretations Committee according to which, in the case of unincorporated joint operations, the operator recognises the entire lease liability, as, by signing the contract, it has primary responsibility for the liability towards the third-party supplier. Therefore, if based on the contractual provisions and any other relevant facts and circumstances, Eni has primary responsibility, it recognises on the balance sheet: (i) the entire lease liability and (ii) the entire right-of-use asset, unless, based on the contractual provisions, there is a sublease with the followers. In particular, the amount of the lease liabilities at January 1, 2019, includes the share of the lease liabilities corresponding to the followers’ working interest for €2.0 billion, while the Eni working interest is €3.7 billion.

On initial application, Eni has elected to apply the following practical expedients allowed by IFRS 16:

possibility to not reassess each contract existing at January 1, 2019, by applying IFRS 16 to all contracts previously identified as leases (under IAS 17 and IFRIC 4), while not applying IFRS 16 to contracts that were not previously identified as leases;

for contracts previously classified as operating leases, possibility to measure the right-of-use asset at an amount equal to the lease liability, adjusted, if necessary, by any prepaid amounts already recognised on the balance sheet;

as an alternative to performing an impairment review, possibility to adjust the right-of-use asset, existing at January 1, 2019, by the amount of any provision for onerous lease contracts recognised at December 31, 2018;

possibility to exclude initial direct costs from the measurement of the right-of-use asset at January 1, 2019.

Moreover, on transition, Eni has elected to not consider leases for which the lease term ends within 12 months of January 1, 2019 as short-term leases.

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The breakdown of the abovementioned quantitative effects and reclassifications deriving from the initial application, as at January 1, 2019, of IFRS 16, is as follows:

(€ 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

The reconciliation between the amount of future minimum lease payments under non-cancellable operating leases at December 31, 2018, discounted using the lessee’s incremental borrowing rate at the date of initial application of IFRS 16, and the opening balance of the lease liabilities at January 1, 2019, is provided below:

(€ 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

In particular, the weighted average discount rate used to measure the lease liabilities as at January 1, 2019 is equal to 6.8%.

Moreover, starting from January 1, 2019 the following IFRSs are effective:

(i)

the amendments to IAS 28 “Long-term Interests in Associates and Joint Ventures”, which clarify that entities account for any financing receivables towards an associate or joint venture, for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests) that, in substance, form part of the entity’s net investment in the investee, using the requirements of IFRS 9, including those related to impairment. These amendments did not have a significant impact on the Consolidated Financial Statements;

(ii)

IFRIC 23 “Uncertainty over Income Tax Treatments”, which clarifies the accounting for (current and/or deferred) tax assets and liabilities when there is uncertainty over income tax treatments. In particular, if there is uncertainty over income tax treatments, if the company concludes it is

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probable that the taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognised in the financial statements consistent with the tax treatment used or planned to be used in its income tax filings. Conversely, if the company concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognised in the financial statements. IFRIC 23 did not have a significant impact on the measurement of income taxes. Nevertheless, with reference to the presentation on the primary financial statements, in September 2019, the IFRS Interpretations Committee has indicated that the uncertain tax assets and liabilities shall be presented in the line items where income tax assets and income tax liabilities are recognised, and not in other line items. In this regard, as the uncertain tax liabilities include also the provisions for litigation concerning income taxes, these provisions have been reclassified out of the line item “Provisions” into the new line item “Income tax liabilities” within the non-current section of the balance sheet. Moreover, the balance sheet has been integrated with the new line items “Income tax assets”, within the non-current section, to present assets (other than deferred tax assets) related to income taxes, in specific, and not residual, line items.35

Furthermore, starting from 2019, on the balance sheet, within the current section, the line items “Other tax receivables” and “Other tax payables” have been deleted and the related amounts have been reclassified into the line items “Other assets” and “Other liabilities”. This change has been carried out because the separate presentation is not considered useful to understand the Group’s financial position.

The balance sheet as at January 1, 2018 has been presented due to the material effect of such reclassifications.

4 IFRSs not yet adopted

On May 18, 2017, the IASB issued IFRS 17 “Insurance Contracts” (hereinafter IFRS 17), which sets out the accounting for the insurance contracts issued and the reinsurance contracts held. IFRS 17, which replaces IFRS 4 “Insurance Contracts”, shall be applied for annual reporting periods beginning on or after January 1, 2021.

On March 29, 2018, the IASB issued the document “Amendments to References to the Conceptual Framework in IFRS Standards”, which includes, basically, technical and editorial changes to existing IFRS standards in order to update references in those standards to previous versions of the IFRS Framework with the new Conceptual Framework for Financial Reporting, issued by the IASB on the same date. These amendments shall be applied for annual reporting periods beginning on or after January 1, 2020.

On October 22, 2018, the IASB issued amendments to IFRS 3 “Business Combinations” (hereinafter the amendments to IFRS 3), which clarify the definition of a business. The amendments to IFRS 3 shall be applied for annual reporting periods beginning on or after January 1, 2020.

On October 31, 2018, the IASB issued amendments to IAS 1 and IAS 8 “Definition of Material” (hereinafter the amendments to IAS 1 and IAS 8), which clarify, and align across all IFRS Standards and other publications, the definition of material to help companies make better materiality judgements. In particular, information is material if omitting, misstating or obscuring it could be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements. The amendments to IAS 1 and IAS 8 shall be applied for annual reporting periods beginning on or after January 1, 2020.

On September 26, 2019, the IASB issued amendments to IFRS 9, IAS 39 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. The amendments to IFRS 9, IAS 39 and IFRS 7 shall be applied for annual reporting periods beginning on or after January 1, 2020.

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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On January 23, 2020, the IASB issued amendments to IAS 1 “Presentation of Financial Statements: Classification of Liabilities as Current ~~assets~~or Non-current” (hereinafter amendments to IAS 1), which clarify how to classify debt and other liabilities as current or non-current. The amendments to IAS 1 shall be applied for annual reporting periods beginning on or after January 1, 2022.

8Eni is currently reviewing the IFRSs not yet adopted in order to determine the likely impact on the Consolidated Financial Statements.

5 Cash and cash equivalents

Cash and cash equivalents of ~~€5,674~~€5,994 million (€~~5,209~~10,836 million at December 31, ~~2015)~~2018) included financial assets with maturity generally of up to three months ~~or less~~ at the date of inception amounting to ~~€4,379~~€3,984 million (€~~3,289~~8,732 million at December 31, ~~2015)~~2018) and mainly included short-term deposits in euro and U.S. dollars with financial institutions, having notice of more than 48 ~~hours.~~hours, to meet the Group’s short-term financing needs.

Restricted cash amounted to €198 million.

The average maturity of ~~financial assets due within 90 days~~bank deposits in euro of €3,086 million was 79 days and the ~~average~~effective interest rate was a negative ~~and amounted to 0.01% (positive 0.25% at December 31, 2015)~~0.22%; the average maturity of bank deposits in U.S. dollars of €864 million was 8 days with an effective interest rate of 1.95%.

96 Financial assets held for trading

(€ million)	December 31, 2015		December 31, 2016		December 31, 2019		December 31, 2018
Quoted bonds issued by sovereign states		925		996
Bonds issued by sovereign states						1,462		1,083
Other		4,103		5,170		5,298		5,469
		5,028		6,166		6,760		6,552

Financial assets held for trading of €6,166 million (€5,028 million at December 31, 2015) related to Eni SpA for €6,062 million (€5,028 million at December 31, 2015) and to Eni Insurance DAC per €104 million.

~~Financial assets held for trading of Eni SpA include securities subject to lending agreements of €665 million.~~ The Company has established a liquidity reserve as part of its internal targets and financial ~~strategy.~~strategy with a view of ensuring an adequate level of flexibility to the Group development plans and of coping with unexpected fund requirements or difficulties in accessing financial markets. The management of this liquidity reserve is performed through trading activities in view of the financial optimization of returns, within a predefined and authorized level of risk tolerance, targeting the preservation of the invested capital and the ability to promptly convert it into cash.

Financial assets held for trading include securities subject to lending agreements of €1,347 million (€1,301 million at December 31, 2018).

The breakdown by currency is provided below:

(€ million) December 31, 2015 December 31, 2016
Euro 3,906 4,319
U.S. dollar 272 699
British pound 271 632
Swiss franc 524 413
Canadian dollar 36 52
Australian dollar 19 51
5,028 6,166

(€ million)	December 31, 2019		December 31, 2018
Euro		4,272		4,573
U.S. dollars		2,279		1,614
Other currencies		209		365
		6,760		6,552

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TABLE OF CONTENTS

The breakdown by issuing entity and credit rating is presented below:

	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		539		548	Baa2	BBB-		734		743	Baa3	BBB
Spain		158		166	Baa2	BBB+
Poland		62		64	A2	BBB+
Slovenia		33		36	Baa3	A
Germany		23		24	Aaa	AAA
Ireland		10		11	A3	A+
Chile		8		8	Aa3	AA-		177		181	A1	A+
Slovakia		5		5	A2	A+
Sweden		5		5	Aaa	AAA
Other(*)								216		224	from Aaa to Baa1	from AAA to BBB+
		843		867				1,127		1,148
Floating rate bonds
Italy		100		100	Baa2	BBB-		126		126	Baa3	BBB
Spain		30		29	Baa2	BBB+
Germany								106		106	Aaa	AAA
Other(*)								81		82	from Aaa to Baa3	from AAA to BBB
		130		129				313		314
Total quoted bonds issued by sovereign states		973		996				1,440		1,462
Other Bonds
Fixed rate bonds
Quoted bonds issued by industrial companies		2,264		2,344	from Aaa to Baa3	from AAA to BBB-		1,183		1,212	from Aa2 to Baa3	from AA to BBB-
Quoted bonds issued by financial and insurance companies		1,981		2,031	from Aaa to Baa3	from AAA to BBB-		862		879	from Aa3 to Baa3	from AA- to BBB-
European Investment Bank		8		8	Aaa	AAA
Other bonds								105		106	from Aaa to Baa2	from AAA to BBB
		4,253		4,383				2,150		2,197
Floating rate bonds
Quoted bonds issued by industrial companies								1,530		1,535	from Aa1 to Baa3	from AA+ to BBB-
Quoted bonds issued by financial and insurance companies		553		556	from Aaa to Baa3	from AAA to BBB-		1,116		1,122	from Aa1 to Baa3	from AA+ to BBB-
Quoted bonds issued by industrial companies		231		231	from Aaa to Baa3	from AAA to BBB-
Other bonds								444		444	from Aaa to Baa2	from AAA to BBB
		784		787				3,090		3,101
Total other bonds		5,037		5,170				5,240		5,298
Total other financial assets held for trading		6,010		6,166				6,680		6,760

~~The fair value was determined based on market quotations.~~

(*)

Amounts included herein are lower than €50 million.

The fair value hierarchy is level 1.

~~10 Financial assets available~~1 for ~~sale~~

(€ million) December 31, 2015 December 31, 2016
Securities held for operating purposes
Quoted bonds issued by sovereign states 243
Quoted securities issued by financial institutions 39
282
Securities held for non-operating purposes
Quoted bonds issued by sovereign states 210
Quoted securities issued by financial institutions 28
238
Total 282 238

~~The breakdown by currency is provided below:~~

(€ million) December 31, 2015 December 31, 2016
Euro 241 199
U.S. Dollar 41 39
282 238

~~F-34~~

~~TABLE OF CONTENTS~~

~~At December 31, 2016, bonds issued by sovereign states amounted to €210~~€6,219 million ~~(€243 million at December 31, 2015). The breakdown is presented below:~~

Nominal
value
(€ million)

Fair
Value
(€ million)
Nominal rate
of return (%) Maturity date Rating –
Moody’s Rating –
S&P
Fixed rate bonds
Belgium 27 32 from 3.75 to 4.25 from 2019 to 2021 Aa3 AA
Spain 25 28 from 1.40 to 5.50 from 2018 to 2021 Baa2 BBB+
Italy 22 22 from 0.00 to 3.50 from 2017 to 2020 Baa2 BBB-
France 17 19 from 1.00 to 3.25 from 2018 to 2023 Aa2 AA
Poland 16 19 from 4.50 to 6.38 from 2019 to 2022 A2 BBB+
Ireland 16 18 from 0.80 to 4.40 from 2019 to 2022 A3 A+
Iceland 15 16 from 2.50 to 5.88 from 2020 to 2022 A3 BBB+
Slovakia 10 10 from 1.50 to 4.20 from 2017 to 2018 A2 A+
Finland 9 9 from 1.13 to 1.75 from 2017 to 2019 Aa1 AA+
Portugal 7 8 4.75 2019 Ba1 BB+
Czech Republic 7 8 3.63 2021 A1 AA-
Slovenia 7 8 2.25 2022 Baa3 A
United States of America 7 7 from 1.25 to 3.13 from 2019 to 2020 Aaa AA+
Canada 5 5 1.63 2019 Aaa AAA
Netherlands 1 1 4.00 2018 Aaa AAA
Total 191 210

~~Quoted securities amounting to €28 million (€39 million at December 31, 2015)~~and level 2 for €541 million. During 2019, there were ~~issued by financial institutions with a rating from Aaa to Aa1 (Moody’s) and from AAA to AA (S&P).~~

~~Securities held for non-operating purposes of €238 million related to~~no transfers between the ~~Group’s insurance company Eni Insurance DAC.~~

From January 1, 2016, insurance companies are required to meet certain capital and solvency ratios as minimum requirements to continue performing the insurance activity based on the provisions of EU Solvency II Directive (the so-called Minimum Capital Requirement — MCR — and Solvency Capital Requirement — SCR). Therefore, while it is advisable to maintain a sound investment policy of the proceeds associated with the business, insurance companies have been waived from committing financial assets to funding the loss provisions. Accordingly, available-for-sale securities held by Eni’s subsidiary Eni Insurance DAC at the opening balance for €282 million have been reclassified as held for non-operating purposes. The same reclassification has been applied to financial receivables held by Eni Insurance DAC (see note 11 — Trade and other receivables).

~~The effects~~different hierarchy levels of fair ~~value measurement of securities are set out below:~~

(€ million) Carrying
amount at
December 31,
2015 Changes
recognized in
equity Reversal of the
year Carrying amount
at December 31,
2016
Fair value 9 (3) (1) 5
Deferred tax liabilities (1) (1)
Other reserves of shareholders’ equity 8 (3) (1) 4

~~The fair value was determined based on market quotations. The fair value hierarchy is level 1.~~

value.

~~F-35~~

~~TABLE OF CONTENTS~~

117 Trade and other receivables

(€ million)	December 31, 2015		December 31, 2016		December 31, 2019		December 31, 2018
Trade receivables		12,616		11,186		8,519		9,520
Financing receivables
- for operating purposes – short-term		375		86
- for operating purposes – current portion of long-term receivables		1,247		72
- for non-operating purposes		685		385
Receivables from divestments						30		122
Receivables from joint ventures in exploration and production activities						2,637		3,024
Other receivables						1,687		1,435
		2,307		543		12,873		14,101
Other receivables
- from disposals		33		171
- other		6,684		5,693
		6,717		5,864
		21,640		17,593

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

Trade receivables decreased by ~~€1,430~~€1,001 million, of which ~~€1,298~~€874 million ~~in the Gas & Power segment because an increased volume of receivables were sold to financial institutions as a result of factoring transactions.~~

~~Receivables are stated net of the valuation allowance for doubtful accounts of €2,371 million (€2,083 million at December 31, 2015):~~

(€ million) Carrying
amount at
December 31,
2015 Additions Deductions Other changes Carrying
amount at
December 31,
2016
Trade receivables 1,915 503 (607) 6 1,817
Financing receivables 66 2 68
Other receivables 102 367 (4) 21 486
2,083 870 (611) 29 2,371

Additions to allowance for doubtful accounts amounted to €503 million (€588 million in 2015) and related mainly to the Gas & Power segment for €399 million. This is reflective of the continuing difficulties in the collection of overdue receivables in the retail customers segment. The mitigation measures regarding the counterparty risk executed by Eni through specific actions of recovery and through specialized external services have led to a reduction of overdue receivables during the year 2016.

~~Utilizations amounting to €607 million (€249 million in 2015)~~ related to the Gas & Power segment ~~for €559 million~~following a drop in prices and ~~related~~volumes of gas sold in the fourth quarter 2019 compared to the ~~recognition~~same period of ~~losses on doubtful accounts in the retail business.~~2018.

At December 31, ~~2016,~~2019, Eni sold without recourse ~~trade~~ receivables due in ~~2017~~2020 for ~~€1,769~~€1,782 million ~~to financial institutions~~ (€~~750~~1,769 million at December 31, ~~2015~~2018 due in ~~2016)~~2019). Derecognized receivables related to the Gas & Power segment ~~(€1,434 million)~~for €1,369 million and to the Refining & Marketing and Chemical ~~segment (€335 million).~~business line for €413 million.

~~Trade receivables outstanding at December 31, 2016 comprised receivables~~Receivables from divestments decreased by €92 million during 2019 due to the collection of ~~€1,764~~the last installment of €123 million ~~for hydrocarbons supplies made by the Exploration & Production segment~~related to national oil companies. That amount includes overdue receivables related to: (i) State-owned oil companies in Egypt, which overdue amount was €420 million. This was significantly lower than the overdue amount of €771 million outstanding at December 31, 2015 and was driven by the implementation of a plan intended to trim the overdue amounts, which comprised the settlement of certain commercial and industrial agreements with the counterparties. The residual amount outstanding at the reporting date has been further reduced by a payment dated January 2017 amounting to $240 million (€228 million); (ii) State-owned companies in Iran as part of a settlement agreement signed in 2015 regarding the recovery of past costs associated to certain petroleum projects already completed for €264 million. This amount was curtailed compared to December 31, 2015 (€312 million). The State counterparties expressed their willingness to negotiate a repayment plan of overdue receivables based on arrangements relating the sale of ~~volumes of~~a 10% interest in the ~~Iranian counterpart equity crude and the attribution~~Zohr asset in Egypt made to ~~Eni of a percentage of the sale proceeds. This agreement~~BP in 2017.

~~F-36~~F-41

TABLE OF CONTENTS

Receivables from joint ventures in exploration and production activities included amounts due by partners in unincorporated joint operations in Nigeria for €1,052 million (€977 million at December 31, 2018) in respect of the contractual recovery of expenditures incurred at certain projects operated by Eni. The amount due by the Nigerian national oil company NNPC was €764 million (€681 million at December 31, 2018), of which 70% is overdue. This overdue amount is subject to a “Repayment Agreement”, whereby Eni is to be reimbursed through the sale of the profit oil attributable to NNPC in certain rig-less petroleum initiatives with low mineral risk. Based on Eni’s Brent price scenario, the reimbursement will be accomplished over a time horizon of three to five years. This plan has ~~been firstly enacted in~~allowed to recover about 45% of the ~~last months~~original amount from the implementation of ~~2016 with~~the agreement two years ago. The overdue receivable is stated net of a ~~reimbursement~~discount factor. A local oil company owed us about €113 million, net of a provision based on the loss given default (LGD) defined by Eni for international oil companies. Initiatives for the definition of a repayment plan are underway. A receivable of equivalent amount was reclassified to non-current assets following the definition of a repayment plan based on the attribution to Eni of ~~$44~~the proceeds for the sale of the productions attributable to the partner. This receivable has been considered as performing because the production is operated by Eni.

Other receivables comprised the recoverable amounts for €373 million (€~~42 million). Negotiations are underway~~300 million at December 31, 2018) of certain overdue trade receivables towards the state-owned oil company of Venezuela, PDVSA, in relation to ~~identify additional crude~~gas equity volumes supplied by the joint venture Cardón IV, equally participated by Eni and Repsol. Those trade receivables were agreed to be ~~marketed, some~~transferred from the joint venture to the two shareholders. The receivables are stated net of ~~which have already been awarded~~an allowance for doubtful accounts determined on the basis of the average recovery percentages obtained by creditors in the context of sovereign defaults, adjusted to ~~Eni~~reflect the strategic value of the Oil&Gas sector, and also applied for assessing the recoverability of the carrying amount of the investment and the long-term interest in ~~early 2017, with~~ the ~~aim of fully recovering the overdue amounts.~~initiative, as described in note 16 — Other financial assets.

~~The ageing of~~Trade and other receivables stated in euro and U.S. dollars amounted to €6,303 million and €5,480 million, respectively.

Credit risk exposure and expected losses relating to trade and other receivables ~~is presented below:~~

December 31, 2015 December 31, 2016
(€ million) Trade
receivables Other
receivables Trade
receivables Other
receivables
Neither impaired nor past due 9,814 5,371 9,243 4,869
Impaired (net of the valuation for doubtful
accounts) 1,085 93 759 432
Not impaired and past due in the following periods:
- within 90 days 1,080 92 744 58
- 3 to 6 months 110 502 49 81
- 6 to 12 months 226 485 69 249
- over 12 months 301 174 322 175
1,717 1,253 1,184 563
12,616 6,717 11,186 5,864

~~The Group~~ has ~~not booked any~~been prepared on the basis of internal ratings as follows:

	Performing receivables						Defaulted receivables		Eni gas e luce customers		Total
(€ million)	Low risk		Medium Risk		High Risk		Defaulted receivables		Eni gas e luce customers		Total
December 31, 2019
Business customers		1,922		2,882		840		1,396				7,040
National Oil Companies and public administrations		1,201		472		244		2,710				4,627
Other counterparties		1,646		103		381		217		2,105		4,452
Gross amount		4,769		3,457		1,465		4,323		2,105		16,119
Allowance for doubtful accounts		(13)		(4)		(16)		(2,547)		(666)		(3,246)
Net amount		4,756		3,453		1,449		1,776		1,439		12,873
Expected loss (% net of counterpart risk mitigation factors)		0.3		0.1		1.1		58.9		31.6		20.1
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

Eni has classified its business customers and the associated commercial or industrial exposures based on an individual assessment of the credit merit and the counterparty ~~loss on certain trade~~risks. Business customers other than National Oil Companies (NOC) and ~~other receivables which were overdue at the balance sheet date, because they pertained to highly-rated Italian and foreign~~ public administrations, each of whom have undergone specific credit evaluations, have been assigned a probability of default calculated based on internal ratings which factor in: (i) a full assessment of each customer profitability, financial condition and liquidity and business a financial prospects on an ongoing basis; (ii) history of the contractual relationship (timeliness in invoice

F-42

TABLE OF CONTENTS

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 ~~other highly-reliable counterparties for supplies~~perform the impairment review of ~~oil, natural~~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 ~~refined~~e luce”, which engages in marketing gas and ~~chemical products~~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 ~~overdue by less than 90 days.~~

~~Trade receivables in currencies other than euro amounted to €3,629 million (€3,995 million at December 31, 2015).~~

~~Financing receivables associated with operating purposes of €158 million (€1,622 million at December 31, 2015) included loans granted to joint ventures and associates to fund~~was assessed on the execution of Eni’s capital projects for €28 million (€1,135 million at December 31, 2015). The decrease for €1,464 million comprised the reclassification for €1,054 million to other non-current financial assets of the financing loan granted to the equity-accounted investee CARDÓN IV SA (Eni’s share being 50%) (€1,112 million at December 31, 2015).

Financing receivables for operating purposes outstanding at December 31, 2015, of €287 million relating to Eni Insurance DAC were reclassified as financing receivables not associated with operating activities following the adoption of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale.

Financing receivables not associated with operating activities amounted to €385 million (€685 million at December 31, 2015) and related to: (i) restricted deposits in escrow for €137 million of Eni Trading & Shipping SpA (€209 million at December 31, 2015) of which €113 million with BNP Paribas and €24 million with Citibank relating to derivatives; (ii) deposits of Eni Insurance DAC for €225 million.

~~Financing receivables in currencies other than euro amounted to €121 million (€1,329 million as of December 31, 2015).~~

Receivables from divestments amounted to €171 million (€33 million at December 31, 2015), of which €166 million related to the current portion of the receivable arising from the divestment finalized in 2008basis of a 1.71% interest in the Kashagan project to the local partner KazMunayGas for a total amount of €463 million. The reimbursement of the receivable is scheduled in three annual instalments commencing from the date when the agreed production target is achieved. The receivable accrues interest income at market rates. Due to the restart of the project, the production milestone was reached in the fourth quarter 2016 and, consequently, the first installment of the sale price including interests has been repaid (€152 million). The description of the transaction is provided in note 23 — Other non-current assets.provision matrix as follows:

Other receivables of €5,693 million (€6,684 million at December 31, 2015) included €4,111 million of receivables owed by Eni’s partners in unincorporated joint ventures that are currently executing exploration

	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

~~F-37~~F-43

TABLE OF CONTENTS

Trade and ~~production projects. The largest outstanding amount as~~other receivables are stated net of ~~December 31, 2016 related~~the allowance for doubtful accounts which has been determined considering the counterparty risk mitigation factors amounting to ~~partners in Nigeria (€1,775 million) and among these the Nigerian national oil company NNPC in respect of: (i) receivables of €382~~€2,914 million (€~~773~~3,072 million at December 31, ~~2015)~~2018):

(€ million)	2019		2018
Carrying amount – beginning of the year		3,150		2,639
Changes in accounting policies (IFRS 9)				427
Carrying amount – restated		3,150		3,066
Additions on trade and other performing receivables		95		126
Additions on trade and other defaulted receivables		525		372
Deductions on trade and other performing receivables		(119)		(189)
Deductions on trade and other defaulted receivables		(484)		(532)
Other changes		79		307
Carrying amount – end of the year		3,246		3,150

Additions to allowance for doubtful accounts on trade and other performing receivables related for €67 million (€108 million in 2018) to the Gas & Power segment, particularly in the retail business; in the Exploration & Production segment provisions of €23 million (€16 million in 2018) related to cash calls towards joint operators — State oil Companies or International Oil Companies — in oil projects operated by Eni.

Additions to allowance for doubtful accounts on trade and other defaulted receivables related to the ~~contractual recovery~~Exploration & Production segment for €339 million (€291 million in 2018) and were in relation with receivables for the supply of ~~costs incurred~~equity hydrocarbons to State-owned companies and receivables towards joint operators for ~~two~~cash calls in oil projects ~~(one~~operated by Eni.

Utilizations of which is operated) under arbitration procedures. After the issuance of favorable arbitration rulings, the Company is negotiating a settlement agreement with the aim of being reimbursed of a part of the amount awarded by the arbitration procedures. The amount being negotiated will be reimbursed through the assignmentallowance for doubtful accounts on trade and other performing and defaulted receivables amounted to ~~Eni of crude oil quantities owned by the state company over a period of three years. The impairment loss~~€603 million (€721 million in 2018) and mainly related to the ~~receivables resulting from~~Gas & Power segment for €385 million (€613 million in 2018), in particular utilizations against charges of €344 million (€579 million in 2018) mainly in the ~~agreement under negotiation amounted~~retail business. The mitigation measures regarding the counterparty risk executed by the Company, including better customer selection, allowed to ~~€332~~reduce the incidence of unpaid amounts on retail sales of gas and power to physiological levels. Utilizations in Exploration & Production segment of €177 million ~~plus the discount effect of the expected future cash flows, which reflected the mineral risk~~ (€~~42 million); (ii) receivables of €716~~66 million ~~were overdue at the balance sheet date~~ in ~~relation~~2018) related to the ~~cash calls owed by NNPC at certain projects operated by Eni. At~~progress in the ~~opening balance, part~~collection of these receivables was denominated in local currency and consequently their carrying amounts were negatively affected by the currency devaluation occurred in 2016. Eni and NNPC agreed on a repayment plan providing for a reimbursement in U.S. dollars and the attribution to Eni of a portion of the proceeds from the sale of the hydrocarbon productions which will be obtained from development activities with a low risk profile (rigless) in order to fully repay the overdue amounts ~~within a period of five years. The expenses through profit included foreign exchange losses~~ for ~~$80 million (€72 million) and the discounting effect for $96 million (€87 million), which was determined taking into account the mineral risk.~~cash calls.

~~Other receivables were as follows:~~

(€ million) December 31, 2015 December 31, 2016
Receivables originated from divestments 33 171
Accounts receivable from
- joint venture partners in exploration and production 4,656 4,111
- prepayments for services 540 372
- insurance companies 113 147
- non-financial government entities 104 49
- factoring arrangements 90 81
- non-Italian oil entities for oil tax refunds 27 40
- other receivables 1,154 893
6,684 5,693
6,717 5,864

Receivables from joint venture partners in exploration and production activities of €60 million (€281 million at December 31, 2015) included the liability for benefit plans (see note 31 — Provisions for employee benefits).

Receivables from factoring arrangements of €81 million (€90 million at December 31, 2015) related to Serfactoring SpA and consisted of advances for factoring arrangements with recourse and receivables for factoring arrangements without recourse.

~~Other receivables in currencies other than euro amounted to €5,253 million (€5,913 million at December 31, 2015).~~

~~Because of the short-term maturity and conditions of remuneration~~Net (impairment losses) reversals of trade and other receivables ~~the fair value approximated the carrying amount.~~are disclosed as follows:

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

Receivables with related parties are ~~described~~disclosed in note 4736 — Transactions with related parties.

~~F-38~~F-44

TABLE OF CONTENTS

~~12 Inventories~~8 Non-current and current inventories

December 31, 2015 December 31, 2016
(€ million) Crude oil,
gas and
petroleum
products Chemical
products Other Total Crude oil,
gas and
petroleum
products Chemical
products Other Total
Raw and auxiliary materials and consumables 222 142 1,933 2,297 550 135 1,903 2,588
Products being processed and semi-finished products 97 9 1 107 99 9 1 109
Work in progress 7 7 2 2
Finished products and goods 1,573 448 72 2,093 1,394 389 86 1,869
Certificates and emission rights 75 75 69 69
1,892 599 2,088 4,579 2,043 533 2,061 4,637

~~Other~~Current inventories ~~of raw~~are disclosed as follows:

(€ million)	December 31, 2019		December 31, 2018
Raw and auxiliary materials and consumables		950		889
Consumables for infrastructure and facility maintenance of perforation activities		1,477		1,451
Finished products and goods		2,284		2,274
Work in progress		8
Certificates and emission rights		15		37
		4,734		4,651

Raw and auxiliary materials and consumables ~~of €1,903 million (€1,933 million at December 31, 2015)~~include oil-based feedstock, catalysts and other consumables pertaining to refining and chemical activities.

Materials and supplies include materials to be consumed in drilling activities and spare parts related to the Exploration & Production segment for ~~€1,699~~€1,359 million (€~~1,732~~1,334 million at December 31, ~~2015)~~2018).

Finished products and ~~primarily comprised materials relating to perforation activities~~goods included gas and ~~the maintenance of infrastructures~~petroleum products for €1,467 million (€1,543 million at December 31, 2018) and ~~facilities.~~chemical products for €547 million (same amount at December 31, 2018).

Certificates and emission rights ~~of €69 million (€75 million at December 31, 2015)~~ are measured at the fair value ~~determined~~ based on market ~~quotations.~~prices. The fair value hierarchy is level 1.

Inventories of ~~€82~~€95 million ~~(€87 million~~(same amount at December 31, ~~2015)~~2018) were pledged to guarantee the ~~potential balancing with respect to~~estimated imbalance in volumes input to/off-taken from the national gas network operated by Snam Rete Gas SpA.

~~Changes in inventories and in the loss provision were as follows:~~

(€ million) Carrying
amount at
the beginning
of the year Changes New or
increased
provisions Deductions Currency
translation
differences Other
changes Carrying
amount
at the end
of the year
2015
Gross carrying amount 8,027 (1,082) 249 (2,307) 4,887
Loss provision (472) (93) 212 (10) 55 (308)
Net carrying amount 7,555 (1,082) (93) 212 239 (2,252) 4,579
2016
Gross carrying amount 4,887 (29) 61 (27) 4,892
Loss provision (308) (125) 163 (5) 20 (255)
Net carrying amount 4,579 (29) (125) 163 56 (7) 4,637

~~Negative changes~~Inventories are stated net of ~~the period amounting to €29~~write-down provisions of €377 million (€578 million at December 31, 2018).

Inventories held for compliance purposes of €1,371 million (€1,217 million at December 31, 2018) related to Italian subsidiaries for €1,353 million (€1,200 million at December 31, 2018) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.

9 Income tax receivables and payables

(€ million)

December 31, 2019

December 31, 2018

Receivables

Payables

Receivables

Payables

Current

Non-Current

Current

Non-Current

Current

Non-Current

Current

Non-Current

Income taxes

192

173

456

454

191

168

440

287

Income taxes are described in note 32 — Income tax expense.

Non-current income tax payables include the ~~Chemical business line for €96 million partially offset by the increase~~likely outcome of pending litigation with tax authorities in ~~the Refining & Marketing segment for €75 million. The increase in loss provision~~relation to uncertain tax matters relating to foreign subsidiaries of ~~€125 million related to~~ the Exploration & Production segment for ~~€72 million. Deductions of €163~~€362 million ~~for loss provision primarily related to the Refining & Marketing business line~~ (€~~122 million).~~

~~Other changes of €2,252~~255 million ~~as of~~at December 31, ~~2015, included the reclassification of €2,183 million as discontinued operations.~~

~~13 Current tax assets~~

(€ million) December 31, 2015 December 31, 2016
Italian subsidiaries 182 134
Subsidiaries outside Italy 178 249
360 383

~~Income taxes are described in note 43 — Income tax expense.~~2018).

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TABLE OF CONTENTS

1410 Other ~~current tax~~ assets and liabilities

(€ million) December 31, 2015 December 31, 2016
VAT 386 447
Excise and customs duties 121 161
Other taxes and duties 123 81
630 689

~~15 Other current assets~~

(€ million)					December 31, 2019								December 31, 2018
					Assets				Liabilities				Assets				Liabilities
	December 31, 2015		December 31, 2016		Current		Non-current		Current		Non-current		Current		Non-current		Current		Non-current
Fair value of derivative financial instruments		3,220		2,248		2,573		54		2,704		50		1,594		68		1,445		40
Other current assets		422		343
Contract liabilities										1,669		456						1,108		518
Other Taxes						766		223		1,411		63		561		254		1,432		34
Other						633		594		1,362		1,042		664		302		1,427		883
		3,642		2,591		3,972		871		7,146		1,611		2,819		624		5,412		1,475

The fair value related to derivative financial instruments is disclosed in note 3423 — Derivative financial ~~instruments.~~instruments and hedge accounting.

~~Other assets amounting~~Assets related to ~~€343~~other current taxes refer to VAT for €742 million, of which €557 million are current, and related to advances made in December (€~~422~~608 million at December 31, ~~2015) included~~2018, of which €383 million current).

Other assets include: (i) gas volumes prepayments that were made in previous ~~reporting period~~years due to the take-or-pay obligations in relation to the Company’s long-term supply contracts asof €174 million (€26 million at December 31, 2018); in 2019 the Company ~~is forecasting~~opted to ~~make-up~~increase the take-or-pay advance with a view of optimizing its gas portfolio, expecting to recover the underlying ~~gas~~ volumes within the next year; (ii) non-current receivables for investing activities for €11 million (€9 million at December 31, 2018).

Contract liabilities included: (i) advances denominated in local currency of €1,228 million (€716 million at December 31, 2018) 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 ~~next 12 months. The residual amount as~~Country, in particular, among these, the Zohr project; (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 million (€66 million at December 31, ~~2016 for €90~~2018); the non-current portion amounted to €455 million ~~reflected the off-taken of underlying volumes achieved during the period that reduced the amount outstanding~~(€518 million at ~~the end of 2015 by €108 million. In 2016, the carrying amount~~December 31, 2018).

Other current liabilities included overlifting imbalances of the ~~prepayment, assimilated~~Exploration & Production segment for €917 million (€1,004 million at December 31, 2018).

Liabilities related to ~~a receivable in kind, was written down by €24~~other current taxes include excise duties and consumer taxes for €628 million ~~to align it to~~(€636 million at December 31, 2018) and VAT liabilities for €311 million (€359 million at December 31, 2018).

Other non-current liabilities include cautionary deposits from retail customers for the ~~current prices~~supply of ~~gas.~~gas and electricity of €231 million (€233 million at December 31 2018).

Transactions with related parties are described in note 4736 — Transactions with related parties.

~~Non-current assets~~

~~16 Property, plant and equipment~~

(€ million) Net book
amount at
the
beginning of
the year Additions Depreciation Net
Impairments/
reversal Write-off Currency
translation
differences Reclassification
to discontinued
operations and
assets held
for sale Other
changes Net book
amount at
the end
of the year Gross book
amount at
the end
of the year Provisions
for
depreciation
and
impairments
2015
Land 615 1 (13) (98) 5 510 534 24
Buildings 1,633 32 (70) (47) 16 (602) (144) 818 3,374 2,556
Plant and
machinery 47,506 369 (8,403) (3,624) 3,276 (6,264) 7,807 40,667 147,969 107,302
Industrial and
commercial equipment 590 49 (85) (1) (2) 14 (197) (42) 326 1,368 1,042
Other assets 458 57 (88) (6) 17 (37) 2 403 2,169 1,766
Tangible assets in progress and advances 25,189 10,669 (2,312) (676) 2,009 (311) (9,287) 25,281 29,835 4,554
75,991 11,177 (8,646) (5,990) (678) 5,319 (7,509) (1,659) 68,005 185,249 117,244
2016
Land 510 1 (64) 1 (8) 8 448 537 89
Buildings 818 22 (66) (3) 1 (2) 40 810 3,416 2,606
Plant and
machinery 40,667 204 (7,087) 345 (198) 1,329 (1) 15,011 50,270 167,007 116,737
Industrial and
commercial equipment 326 32 (66) (1) (2) 11 300 1,415 1,115
Other assets 403 42 (89) (17) 4 (34) 309 2,160 1,851
Tangible assets in progress and advances 25,281 8,766 (174) (89) 551 (15,679) 18,656 22,737 4,081
68,005 9,067 (7,308) 86 (289) 1,886 (11) (643) 70,793 197,272 126,479

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TABLE OF CONTENTS

~~A breakdown by segment~~11 Property, plant and equipment

(€ million)	Land and buildings		E&P wells, plant and machinery		Other plant and machinery		E&P exploration assets and appraisal		E&P tangible assets in progress		Other tangible assets in progress and advances		Total
2019
Net carrying amount – beginning of the year		1,274		42,856		3,901		1,267		9,195		1,809		60,302
Additions		12		144		223		508		6,170		992		8,049
Depreciation capitalized								14		202				216
Depreciation (*)		(60)		(6,435)		(537)								(7,032)
Reversals		44		65		69				65		139		382
Impairment		(47)		(659)		(500)				(669)		(537)		(2,412)
Write-off						(5)		(216)		(49)				(270)
Disposals		(1)		(3)		(1)		(22)		(80)		(6)		(113)
Currency translation differences		2		815		21		24		181		1		1,044
Initial recognition and changes in estimates				2,028				25		21				2,074
Transfers		42		7,568		597		(42)		(7,526)		(639)
Other changes		(48)		113		(136)		5		(98)		116		(48)
Net carrying amount – end of the year		1,218		46,492		3,632		1,563		7,412		1,875		62,192
Gross carrying amount – end of the year		4,067		144,789		28,191		1,563		11,406		2,799		192,815
Provisions for depreciation and impairments		2,849		98,297		24,559				3,994		924		130,623
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

(*)

Before capitalization of ~~capital expenditures made in 2016 is provided below:~~depreciation

(€ million) 2015 2016
Capital expenditure
Exploration & Production 9,943 8,217
Gas & Power 109 66
Refining & Marketing and Chemical 614 655
Engineering & Construction 550
Corporate and other activities 46 42
Elimination of intragroup profits (85) 87
11,177 9,067

Capital expenditures included capitalized finance expenses of ~~€105~~€93 million (€~~165~~52 million in ~~2015) and~~2018) related to the Exploration & Production segment for €71 million (€~~90 million)~~37 million in 2018). The interest ~~rates~~rate used for capitalizing finance expense ranged from ~~2.7%~~2.6% to ~~5.3% (2.4% and 5.3%~~2.8% (2.3% to 2.4% at December 31, ~~2015)~~2018).

Capital expenditures primarily related to the Exploration & Production segment for €6,889 million (€7,757 million in 2018) and included the consideration of €400 million paid for the acquisition of a proved and unproved mineral interest in an already participated producing field in the United States, an entry bonus in a property under development in Algeria and the residual entry bonus in a concession in the United Arab Emirates; therefore, part of those expenditures increased unproved mineral properties.

More information is reported in note 35 — Segment information and information by geographical area.

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

(%)
Buildings		2 ~~- 10~~– 10
~~Plant~~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	~~2 - 15~~	6 – 12
Industrial and commercial equipment	~~4 - 33~~	5 – 25
Other assets	~~6 - 33~~	10 – 20

~~The criteria adopted by Eni for determining net impairments/reversals is reported in note 19 — Impairment/reversal of tangible and intangible assets.~~

Write-off of €289 million (€678 million in 2015) related for €193 million to the EST conversion plant units at the Sannazzaro refinery, damaged in an accident occurred in December 2016. The Exploration & Production booked €93 million of asset write-offs (€676 million in 2015), of which €88 million mainly relating exploration wells capitalized in previous reporting periods. Wells write-offs comprised suspended exploration wells that did not encountered enough quantities of commercial hydrocarbons to justify their completion as productive wells in Libya, Angola, Congo and Indonesia.

Foreign currency translation differences of €1,886 million primarily related to translations of entities accounts denominated in U.S. dollar (€1,761 million), Norwegian krone (€318 million) and, as decrease, in in British pound (€215 million).

Other changes of €643 million related to the initial recognition and change in estimates of decommissioning costs and site restoration in the Exploration & Production segment amounting to €665 million (€817 million at December 31, 2015) mainly due to a steeper discount rate curve, especially for the U.S. dollar and to the revision of cost estimates. These effects were partially offset by the recognition of new obligations incurred during the year. Other changes in tangible assets in progress and advances of €15,679 million included the reclassification from plant and machinery of the carrying amount of the idle units of the EST plant of the Sannazzaro refinery for €485 million until the re-entry into operations of the damaged section.

~~F-41~~F-47

TABLE OF CONTENTS

~~Tangible~~The criteria adopted by Eni for determining impairment losses and reversal is reported in note 14 — Impairment review of tangible and intangible assets ~~in progress~~ and ~~advances include costs~~right-of-use assets.

Foreign currency translation differences primarily related to ~~exploration activities~~subsidiaries which utilize the U.S. dollar as functional currency (€976 million).

Initial recognition and ~~appraisal~~changes in estimates include the increase in the asset retirement cost of Exploration & Production tangible assets due to the decrease in the discount rate curve and new obligations recorded during the year.

Transfers from E&P tangible assets in progress to E&P UOP wells, plant and ~~advances~~machinery related for €4,560 million to progress in the development of reserves primarily in Egypt, Mexico, Libya, Ghana and Angola.

Changes in 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 of unsuccessful exploration wells costs for €183 million mainly in Australia, Kazakhstan, Pakistan, China and United Kingdom.

Exploration and appraisal activities related for €1,246 million to costs of suspended exploration wells pending final determination and for €317 million to costs of exploration wells in progress at the end of the ~~Exploration & Production segment:~~

(€ million) Book
amount at
the beginning
of the year Additions Net
impairments/
reversals Write-off Reclassifications Other
changes and
currency
translation
differences Book
amount
at the end
of the year
2015
Exploration activity and appraisal
Exploratory wells in progress 196 558 (106) (572) 17 93
Exploratory wells completed and being evaluated 1,568 (501) 520 150 1,737
Exploratory successful wells in progress 813 (91) 5 80 807
2,577 558 (91) (607) (47) 247 2,637
Other tangible assets in progress
Unproved mineral interest 3,092 (998) (203) 321 2,212
Wells and plants in progress 17,958 9,346 (866) (69) (8,107) 1,196 19,458
21,050 9,346 (1,864) (69) (8,310) 1,517 21,670
23,627 9,904 (1,955) (676) (8,357) 1,764 24,307
2016
Exploration activity and appraisal
Exploratory wells in progress 93 402 (282) 8 221
Exploratory wells completed and being evaluated 1,737 (109) 6 50 1,684
Exploratory successful wells in progress 807 (5) 78 33 913
2,637 402 (5) (109) (198) 91 2,818
Other tangible assets in progress
Unproved mineral interest 2,212 2 190 (35) 81 2,450
Wells and plants in progress 19,458 7,777 (210) (6) (15,699) 370 11,690
Abandonment cost 27 55 82
21,670 7,779 (20) 21 (15,734) 506 14,222
24,307 8,181 (25) (88) (15,932) 597 17,040

~~Reclassifications of €15,932 million mainly related~~year. Changes relating to suspended wells and production plants started to production in the year for €15,699 million, particularly due to the start-up of major oil&gas projects such as the Kashagan project in Kazakhstan, the Goliat project in Norway and the ‘Mpungi field in the West Hub project, Block 15/06 in Angola.are showed:

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

The following information relates to the stratification of the suspended wells pending final determination ~~of proved reserves (aging) and the projects to which they relate:~~(ageing):

(€ million) 2014 2015 2016
Costs for exploratory wells suspended at the beginning of the period 1,618 1,568 1,737
Additions pending the determination of proved reserves
373 550 282
Amounts charged to expense (267) (501) (109)
Reclassification to productive wells on determination of proved reserves (314) (30) (276)
Sales (4)
Exchange differences 158 154 50
Costs for exploratory wells suspended at the end of the period 1,568 1,737 1,684

	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

~~F-42~~F-48

TABLE OF CONTENTS

2014 2015 2016
(€ 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 392 7.85 368 5.32 16 1.05
- between 1 and 3 years 756 15.07 634 11.14 609 10.25
- beyond 3 years 420 12.87 735 18.97 1,059 21.55
1,568 35.79 1,737 35.43 1,684 32.85
Costs capitalized for suspended wells
- fields including wells drilled over the last 12 months 392 7.85 368 5.32 9 0.55
- fields for which the delineation campaign is in progress 1,043 21.90 228 4.13 251 3.51
- fields including commercial discoveries that are progressing to sanctioning 133 6.04 1,141 25.98 1,424 28.79
1,568 35.79 1,737 35.43 1,684 32.85

Suspended wells costs awaiting a final investment decision amounted to €505 million and included a significant amount relating to the exploration costs incurred for the Mamba discovery in Mozambique’s offshore Area 4, for which the venture partners are completing the activities for sanctioning the project. The other suspended costs refer to initiatives ongoing in the main countries of presence (Nigeria, Angola, Congo and Egypt), none of which, however, represents an individually significant amount.

Unproved mineral interests include the purchase price allocated to unproved reserves following business combinations or acquisition of individual properties. Unproved mineral interests were ~~recognized in connection with the purchase price allocation~~ as ~~part of business combinations or acquisitions of individual properties:~~follows:

(€ million) Book
amount at
the beginning
of the year Acquisitions Net
reversals
(impairments) Reclassification
to proved
mineral
interest Other
changes and
currency
translation
differences Book
amount
at the end
of the year
2015
Congo 1,214 (201) (127) 135 1,021
Nigeria 823 85 908
Turkmenistan 524 (411) 52 165
Algeria 373 (386) (22) 35
USA 123 (20) 6 109
Egypt 35 (34) 8 9
3,092 (998) (203) 321 2,212
2016
Congo 1,021 190 43 1,254
Nigeria 908 30 938
Turkmenistan 165 (31) 4 138
USA 109 4 113
Egypt 9 2 (4) 7
2,212 2 190 (35) 81 2,450

~~In 2016, Eni recorded reversals of previous impairment losses for €190 million (see note 19 – Impairment/reversal of tangible and intangible assets).~~

(€ million)	Congo		Nigeria		Turkmenistan		USA		Algeria		Egypt		United Arab Emirates		Total
2019
Book amount at the beginning of the year		769		921		77		103		77		29		502		2,478
Additions								97		135		1		23		256
Net (impairments) reversals		(533)				65		(27)								(495)
Reclassification to proved mineral interest						(4)		(14)		(99)		(12)				(129)
Currency translation differences		17		18		1		3		2		1		10		52
Book amount at the end of the year		253		939		139		162		115		19		535		2,162
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 ~~interest~~interests comprised a property ~~known as~~denominated Oil Prospecting License 245 ~~(“OPL 245”)~~(OPL 245), ~~located~~ offshore Nigeria, with a net book value of ~~€932~~€874 million ~~which corresponded~~corresponding to the price paid in 2011 to the ~~Nigeria~~Nigerian Government to acquire a 50% interest in ~~OPL 245,~~the property, together with the partner Shell ~~acquiring~~which acquired the remaining 50%. As of December 31, ~~2016,~~2019, the net book value of the property ~~was €1,255~~amounted to €1,184 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 disclosed in note ~~38 -~~27 — Guarantees, Commitments and Risks. On January 27, 2017, Eni subsidiary Nigerian Agip Exploration Ltd became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court, sitting in Abuja, upon request from the Economic and Financial Crime Commission (EFCC), attaching the property OPL 245, pending the Nigerian proceeding. Both Eni and Shell made a prompt application to discharge the Order. On March 17, 2017, the Nigerian Court discharged the Order. Management has concluded that noThe impairment test of the asset ~~was required. After~~confirmed the ~~inception of the judicial proceeding in Italy, which dates back to July 2014, Eni’s Board of~~

~~F-43~~

~~TABLE OF CONTENTS~~

~~Statutory Auditors jointly with the Eni Watch Structure has engaged~~book value also considering a US leading law firm to perform an independent review of the issue. Based on the outcome of this review, during which the law firm has also assessed material and the information made available from the judicial authorities, no wrongdoing has been detected on Eni sidestress test assuming possible delays in the ~~awarding process to Eni~~start of ~~the license.~~development activities.

Accumulated provisions for impairments amounted to ~~€17,558~~€18,226 million (€~~17,480~~16,471 million at December 31, ~~2015)~~2018).

Property, plant and equipment include assets subject to leases for €241 million.

At December 31, ~~2016,~~2019, Eni pledged property, plant and equipment for €24 million ~~primarily~~to guarantee payments of excise duties (same amount as ~~collateral against certain borrowings (€21 million at~~of December 31, ~~2015)~~2018).

Government grants recorded as a decrease of property, plant and equipment amounted to ~~€90~~€112 million (€96125 million at December 31, ~~2015)~~2018).

~~Assets acquired under financial lease agreements amounted to €29 million (€26 million at December 31, 2015) and related to service stations of the Refining & Marketing business line.~~

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 3827 — Guarantees, commitments and risks — Liquidity risk.

Property, plant and equipment under concession arrangements are described in note ~~38 –~~27 — Guarantees, commitments and risks — Assets under concession arrangements.

~~Property, plant and equipment by segment~~

(€ million) December 31, 2015 December 31, 2016
Property, plant and equipment, gross
Exploration & Production 154,064 165,559
Gas & Power 6,169 6,276
Refining & Marketing and Chemical 23,818 24,119
Corporate and other activities 1,854 1,886
Elimination of intragroup profits (656) (568)
185,249 197,272
Accumulated depreciation, amortization and impairment losses
Exploration & Production 92,569 101,131
Gas & Power 4,287 4,584
Refining & Marketing and Chemical 19,154 19,477
Corporate and other activities 1,436 1,518
Elimination of intragroup profits (202) (231)
117,244 126,479
Property, plant and equipment, net
Exploration & Production 61,495 64,428
Gas & Power 1,882 1,692
Refining & Marketing and Chemical 4,664 4,642
Corporate and other activities 418 368
Elimination of intragroup profits (454) (337)
68,005 70,793

~~17 Inventory — compulsory stock~~

Compulsory inventories of €1,184 million (€909 million at December 31, 2015) were primarily held by Italian subsidiaries for €1,167 million (€893 million at December 31, 2015) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.

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12 Right-of-use assets and lease liabilities

(€ million)	Floating production storage and offloading vessels (FPSO)		Drilling rig		Naval facilities and related logistic bases for oil and gas transportation		Motorway concessions and service stations		Oil and gas distribution facilities		Office buildings		Vehicles		Other		Total
First adoption IFRS 16		3,294		346		569		462		7		720		43		215		5,656
Reclassifications								30								16		46
Reclassifications to assets held for sale																(13)		(13)
Net carrying amount at January 1, 2019		3,294		346		569		492		7		720		43		218		5,689
Additions		32		192		219		54		1		108		22		56		684
Depreciation(a)		(240)		(224)		(272)		(61)		(1)		(115)		(23)		(63)		(999)
Impairment losses								(13)								(28)		(41)
Currency translation differences		67		6		4		2				3				3		85
Other changes				(7)		(23)		(14)		(1)		(9)		(10)		(5)		(69)
Net carrying amount at December 31, 2019		3,153		313		497		460		6		707		32		181		5,349
Gross carrying amount		3,393		528		757		532		7		806		54		274		6,351
Provisions for depreciation and impairment		240		215		260		72		1		99		22		93		1,002

(a)

Before capitalization of depreciation for tangible and intangible assets

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

Right-of-use assets (RoU) related: (i) for €3,895 million to the Exploration & Production segment and mainly comprised the operating leases of certain FPSO vessels hired in connection with operations at offshore development projects in Ghana (OCTP) and Angola (Block 15/06 West and East hub) with expiry date between 10 and 18 years including a renewal option and in addition the lease component of long-term leases of offshore rigs; (ii) for €512 million to the Refining & Marketing and Chemical segment relating to motorway concessions, land leases, leases of service stations for the sale of oil products and the car fleet dedicated to the car sharing business; (iii) for €365 million to the Gas & Power segment relating to the leasing of naval vessels for shipping activities and logistics structures for gas distribution; (iv) for €577 million to the Corporate and Other activities segment mainly regarding property rental contracts.

The main leasing contracts signed for which the asset is not yet available concern: (i) a contract with a nominal value of €2.1 billion relating to an FPSO vessel that will be deployed for the development of Area 1 in Mexico. The asset is expected to enter under the Group’s control and be accounted as RoU in 2021, expiring in 2040; (ii) a contract with a nominal value of €438 million relating to leasing of office building with an expiry date of 20 years with an extension option of 6 years.

The main future cash outflows potentially due not reflected in the measurements of lease liabilities related to: (i) options for the extension or termination of the lease for office buildings of €297 million; (ii) service stations for the sale of oil products of €155 million; (iii) other extension options related to concessions of land for €60 million and ancillary assets in the upstream business for €84 million.

Liabilities for leased assets were as follows:

(€ million)	Current portion of long-term lease liabilities		Long-term lease liabilities		Total
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

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Lease liabilities related for €1,976 million 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 million; (ii) cash payments for the interest portion of €347 million; (iii) prepayment RoU for leased assets for €16 million.

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) Net book
amount at
the beginning
of the year Additions Amortization Net
impairments/
reversals Write-off Currency
translation
differences Reclassification
to discontinued
operations and
assets held
for sale Other
changes Net book
amount
at the end
of the year Gross book
amount at
the end
of the year Provisions
for
amortization
and
impairments
2015
Intangible assets with finite useful lives
Exploration expenditures 1,081 8 (63) (369) (10) 102 (14) 735 2,195 1,460
Concessions, licenses, trademarks and similar items 479 8 (117) (2) (1) (4) 363 2,499 2,136
Industrial patents and intellectual property rights 285 26 (74) 1 (31) 69 276 1,407 1,131
Service concession arrangements 32 (2) 2 32 51 19
Intangible assets in progress and advances 179 54 (7) (7) (71) 148 153 5
Other intangible assets 167 29 (47) (5) 2 (1) 21 166 2,576 2,410
2,223 125 (303) (383) (10) 104 (43) 7 1,720 8,881 7,161
Intangible assets with indefinite useful lives
Goodwill 2,197 (161) 34 (363) (393) 1,314
4,420 125 (303) (544) (10) 138 (406) (386) 3,034
2016
Intangible assets with finite useful lives
Exploration expenditures 735 15 (18) 385 (61) 36 1,092 2,216 1,124
Concessions, licenses, trademarks and similar items 363 6 (113) (1) 255 2,462 2,207
Industrial patents and intellectual property rights 276 26 (81) 38 259 1,467 1,208
Service concession arrangements 32 1 (2) 31 52 21
Intangible assets in progress and advances 148 49 (49) 148 153 5
Other intangible assets 166 16 (39) 4 (4) 21 164 2,599 2,435
1,720 113 (253) 389 (61) 32 9 1,949 8,949 7,000
Intangible assets with indefinite useful lives
Goodwill 1,314 6 1,320
3,034 113 (253) 389 (61) 38 9 3,269

(€ 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

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Exploration rights ~~€1,092 million (€735 million at December 31, 2015)~~ comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on ~~the~~ 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 ~~exploratory~~exploration activity or until management confirms its commitment to the initiative.

~~Reversals~~ Additions for the year related to signature bonuses paid for the acquisition of ~~previous impairment losses of €385 million (impairments losses of €369 million were recorded~~new exploration acreage mainly in ~~2015) were recognized at proved license acquisition costs in Angola~~United Arab Emirates, Mozambique, Mexico and Congo. More information is provided in note 19 — impairments and reversal of tangible and intangible assets. Write-offs for €61 million (€10 million in 2015) were booked at unproved exploratory rights due to the negative outcome of certain exploration projects, the most important being an initiative in Angola.Indonesia.

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

(€ million) December 31, 2015 December 31, 2016
Proved license and leasehold property acquisition costs 90 497
Unproved license and leasehold property acquisition costs 611 579
Other mineral interests 34 16
735 1,092

Concessions, licenses, trademarks and similar items for €255 million (€363 million at December 31, 2015) primarily comprised transmission rights for natural gas imported from Algeria of €223 million (€323 million at December 31, 2015) and concessions for mineral exploration of €13 million (€15 million at December 31, 2015).

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(€ million)	December 31, 2019		December 31, 2018
Proved licence and leasehold property acquisition costs		291		357
Unproved licence and leasehold property acquisition costs		709		684
Other mineral interests		31		40
		1,031		1,081

Industrial patents and intellectual property rights ~~of €259 million (€276 million at December 31, 2015) related to Eni SpA for €235 million (€250 million at December 31, 2015) and essentially concerned costs for~~mainly regarded the acquisition and internal development of software and rights for the use of production processes and software.

~~Service concession arrangements of €31 million primarily pertained to gas distribution activities outside Italy (€32 million at December 31, 2015).~~

Intangible assets in progress and advances of €148 million (same amount as of December 31, 2015) related to Eni SpA for €44 million (€49 million at December 31, 2015) and primarily concerned cost for software development.

Other intangible assets ~~with finite useful lives of €164~~comprised: (i) customer acquisition costs relating to the retail gas business for €226 million (€166 million at December 31, ~~2015) comprised: (i) royalties for the use of licenses by Versalis SpA for €40 million (same amount as of December 31, 2015)~~2018); (ii) ~~the estimated costs of Eni’s social responsibility projects in relation to oil development programs in Val d’Agri~~concessions, licenses, trademarks and ~~in the North Adriatic area connected to mineral rights under concession~~similar items for ~~€41~~€102 million (€49151 million at December 31, ~~2015) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality~~2018) comprised transmission rights for natural gas imported from Algeria of ~~Ravenna.~~

~~The criteria adopted by~~€30 million (€27 million at December 31, 2018); (iii) capital expenditures in progress on natural gas pipelines for which Eni has acquired transport rights for ~~determining net impairments/reversals and the relevant breakdown by segment are reported in note 19 — Impairment/reversal of tangible and intangible assets.~~€78 million (same amount at December 31, 2018).

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

(%)
Exploration rights	~~14 - 33~~	UOP – 33
~~Concessions,~~Transport rights of natural gas		3
Other concessions, licenses, trademarks and similar items	~~3 - 33~~
~~Industrial patents and intellectual property rights~~	~~20 - 33~~3 – 33
Service concession arrangements	~~2 - 4~~	20 – 33
Capitalized costs for customer acquisition		25 – 33
Other intangible assets		4 ~~- 25~~– 20

The carrying amount of goodwill at the end of the year ~~was €1,320~~amounted €2,454 million, ~~(€1,314 million at December 31, 2015)~~ net of cumulative impairments ~~charges amounting to €2,524 million (€2,525 million at December 31, 2015).~~

Acharges. The breakdown ~~of the stated goodwill~~ by ~~operating~~ segment is provided below:

(€ million)	December 31, 2015		December 31, 2016		December 31, 2019		December 31, 2018
Gas & Power		1,025		1,025		981		977
Exploration & Production		196		202		190		187
Refining & Marketing		93		93
Refining & Marketing and Chemicals						93		119
Other activities						1		1
		1,314		1,320		1,265		1,284

~~More information about goodwill is reported in note 19 — Impairment/reversal of tangible and intangible assets.~~

~~19 Impairment/reversal of tangible and intangible assets~~

(€ million) 2015 2016
Impairment losses
Tangible assets (5,993) (1,067)
Intangible assets (544)
(6,537) (1,067)
less:
- reversal of tangible assets 3 1,153
- reversal of intangible assets 389
(6,534) 475

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~~In order to verify the recoverability~~An impairment loss of the carrying amounts of tangible and intangible assets, management assesses at the end of the year whether there are any indications that assets may be impaired. External impairment indicators comprise evidence that the carrying amount of the net assets of Eni are above Eni market capitalization, expectations about future trends in the prices and margins of commodities, forecast trends in monetary variables (interest rates, exchange rates, inflation), country risk or changes in the regulatory/contractual framework. Internal impairment indicators comprise evidence of reservoirs underperformance, increases in costs/investments, obsolescence and other factors. In case of a recovery in the trading environment or better industrial performance with respect to the comparative period, management assesses whether the factors underlying previous impairment losses may no longer exist or may have decreased.

In assessing whether impairment is required, the carrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is the higher of 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.

~~Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified~~entire allocated goodwill was recorded by estimating assets’ values-in-use (VIU). The valuation is carried out for individual asset or for the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets, or groups of assets (cash generating unit — CGU). The Group has identified the following CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields where technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power segment, in addition to the CGUs to which goodwill arisen from business combinations was allocated, electricity generation plants, international pipelines and LNG vessels; (iii) in the Refining & Marketing business line, refining plants, retail networks and assets related to other distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) the Chemical business line ~~has been assessed~~in relation to ~~be a single CGU.~~

~~The value-in-use is calculated by discounting~~activities concerning the ~~estimated future cash flows deriving from the continuing use~~development, industrialization, licensing of ~~the CGUs~~bio-chemical technologies and ~~if significant and reasonably determinable, the cash flows deriving from disposal at the end of their useful lives. Cash flows are determined~~processes based on the ~~best information available at~~use of renewable sources.

An increase in goodwill was recorded in connection with the ~~time~~allocation of the ~~assessment. Cash flow projections~~acquisition cost of the company SEA SpA, which engages in providing services and solutions for energy efficiency in 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, sales volumes, capital expenditure, operating costs and marginsresidential 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 and the associated projections of operating costs and development expenditures. The CGUs of the Refining & Marketing business line and each power plant are evaluated based on the plant economic and technical life and the associated, normalized projections 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%. The Chemical business CGU considers the average economic useful life of the underlying assets and factors a normalized EBITDA (to reflect the cyclicality of the sector) defined based on the average contribution margin of the plan and applying to the fixed costs the expected inflation rate. 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.segments.

~~Values-in-use is estimated by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production and Refining & Marketing to the Company’s weighted average cost of capital~~

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(WACC) net of the risk factors attributable to the Gas & Power segment and the Chemical business line the WACC of which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC). Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

From the second half of 2016, the oil market has staged a recovery on the back of a better balance between global supply and demand of crude oil, driven by cuts in investments made by oil companies during the downturn and by the year-end agreement of OPEC countries to curb the cartel output, joined also by important non-OPEC countries (in particular Russia). Considering the historical minimum reached in the first half of the year, the price of the crude oil has recovered about 60% of its value. Based on those improved fundamentals, management revised upwardly its long-term assumption for the benchmark Brent price to 70$ per barrel in 2020 real terms, from a previous 65$ per barrel, in elaborating the Group financial projections of the 2017 – 2020 industrial plan and the estimations of the financial report 2016. Furthermore, at the balance sheet date, the market capitalization of Eni amounted to €55.7 billion exceeding the book value of the consolidated net assets equal to €53.1 billion, thereby discontinuing a two-year long downward trend.

Finally, the 2016 WACC of Eni, which is the driver for calculating the WACC of the oil&gas and refining business segments to assess the value-in-use of their relevant CGUs, recorded a marginal decrease, down by 0.1 percentage point to 6.4% compared to 2015. This reduction was driven by a lower premium for the sovereign risk incorporated into the yields on Italian ten-year bonds and a marginal a reduction in the cost of borrowings, offset by an increase in the beta of Eni. The WACC used in the Chemical business line decreased by 1 percentage point to 9% due to a lower country risk, considering that the activities are concentrated in Europe, and to the reduction of the risk-free rate. The WACC in the Gas & Power segment increased by 0.4 percentage points to 5.8% due to a higher country risk of some activities outside Europe. The adjusted WACC rates for 2016 highlighted dispersion compared to the average value of Eni amounting to 6.5%. This reflected a noticeable increase in the country risk in certain upstream areas. The adjusted WACC rates used for impairment test purposes in 2016 ranged from 4.8% to 15.0%.

Considering the upward revision of the long-term Brent price, the Company recorded reversals of previous impairment losses in the Exploration & Production segment for a total of €1,440 million reflecting the increased value-in-use of a number of oil&gas assets. The main reversals were recorded at a CGU which includes unproved mineral interests for €190 million, mainly in Congo; license acquisition costs with proved reserves for €385 million, particularly in Angola; property, plant and equipment for €865 million, particularly in Angola, USA, Algeria, Turkmenistan, United Kingdom and Norway. The post-tax WACC relating to reversals of impairments of more than €100 million regarded two CGUs and was 6%, corresponding to a pre-tax rate ranging from 9.64% to 18.13%, respectively.

These reversals, which correspond to about 28% of the impairment losses recorded in 2015, were partially offset by the recognition of impairment losses of €740 million. Those losses were driven by a weaker price outlook in the gas market in Europe, which negatively affected the recoverable amounts of Italian gas CGUs, and by downward reserve revisions, contractual changes and an increased country risk, which negatively impacted the recoverable amounts at a number of oil&gas properties in various locations. Impairment losses of more than €100 million regarded two CGUs with a post-tax WACC ranging from 4.8% to 6.1%, restated in a pre-tax rate ranging from 7.9% to 25.86%.

Impairment losses recognized in the Refining & Marketing business line of €120 million related to the investments of the year for compliance and stay-in-business related to CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review.

Impairment losses net of reversals recognized in the Gas & Power segment amounted to €81 million mainly related to the gas transportation network GreenStream, following the increase in the discount rate for country risk and LNG carriers.

Considering the volatility in the oil scenario and the increased financial and geopolitical instability in certain countries where the Eni’s reserves are located, management assessed the fairness of its assumptions and the outcome of the impairment review by stress testing the headroom of the Group’s properties in high-risk locations. This sensitivity analysis was performed increasing by a full percentage point the discount rate applied to future cash flows with a view of factoring in a higher country risk premium. This exercise comprised Eni’s oil&gas properties in Libya, Egypt, Iraq, Venezuela and Nigeria, which base WACC are still significantly higher than the average WACC of Eni. No major changes in the properties headroom were detected.

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~~A breakdown by segment of impairments losses recorded in 2016 and the associated tax effect is provided below:~~

(€ million) 2015 2016
Impairment losses
Exploration & Production 4,682 740
Gas & Power 153 167
Refining & Marketing and Chemical 1,138 120
Corporate and other activities 20 40
5,993 1,067
Tax effects
Exploration & Production 1,837 216
Gas & Power 38 35
Refining & Marketing and Chemical 38 32
Corporate and other activities 2
1,915 283
Impairments net of the relevant tax effects
Exploration & Production 2,845 524
Gas & Power 115 132
Refining & Marketing and Chemical 1,100 88
Corporate and other activities 18 40
4,078 784

~~A breakdown of impairment losses and reversals in the Exploration & Production segment and the associated tax effect is provided below:~~

(€ million) 2015 2016
Impairments (reversal), net
Impairments of tangible assets 4,682 740
Impairments of intangible assets 530
Reversals of tangible assets (1,055)
Reversals of intangible assets (385)
5,212 (700)
Tax effects
Impairments of tangible assets 1,837 216
Impairments of intangible assets 106
Reversals of tangible assets (315)
Reversals of intangible assets (120)
1,943 (219)
Impairments (reversal) net of the relevant tax effects
Impairments of tangible assets 2,845 524
Impairments of intangible assets 424
Reversals of tangible assets (740)
Reversals of intangible assets (265)
3,269 (481)

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 to the Gas & Power segment. ~~A breakdown is disclosed below.~~

(€ million) December 31, 2015 December 31, 2016
Domestic gas market 835 835
European gas market 190 190
- of which European market 188 188
1,025 1,025

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A breakdown is disclosed below:

(€ million)	December 31, 2019		December 31, 2018
Domestic gas market		839		835
Foreign gas market		142		142
		981		977

Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of the former Italgas SpA minorities in 2003 through a public offering (€706 million). The acquired entity engaged in the retail sale of gas to the residential sector and middle and small-sized businesses in Italy. In addition, further goodwill amounts have been allocated over the years following business combinations with small, local companies selling gas to residential customers in focused territorial reach and municipalities synergic to Eni’s activities. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU, including ~~any allocated goodwill.~~

~~Goodwill allocated to~~ the CGU European gas market, amounting to €188 million, was recorded following the business combinations of Altergaz SA (now Eni Gas & Power France SA) in France, and Nuon Belgium NV (now merged in Eni Gas & Power NV) in Belgium, which represent two stand-alone CGUs. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of both CGUs including any allocated goodwill.

In assessing the recoverability of the carrying amount of the ~~Gas & Power CGUs,~~CGU domestic gas market, including the allocated portion of goodwill, management determined the value in use of ~~those CGUs~~the CGU considering the sales margin exclusively of the retail market (excluding ~~the wholesale~~ margins on sales to wholesalers, industrial and power generation customers). The assessment was performed considering the cash flows of the four-year plan approved by management and incorporating ~~the~~a terminal value calculated as perpetuity of the last year of the plan ~~to determine the terminal value~~ by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of ~~4.5%~~5.3% for ~~Italy and 5.0% for Europe.~~Italy. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

~~The excess~~There are no realistic hypotheses of changes in the discount rate, growth rate, profitability or volumes that would lead to zeroing the headroom amounting to €1,701 million of the ~~recoverable amount~~value in use of the Italian Market CGU with respect to its book value, including the goodwill.

Goodwill allocated to the CGU European gas 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 Domestic gas market ~~over its~~CGU confirmed the recoverability of the carrying amount of these gas market CGUs, including any allocated goodwill, by using a post-tax WACC adjusted considering a country risk for France of 5.9%, and 6.2% for Greece.

14 Impairment review of tangible and intangible assets and right-of-use assets

In assessing whether impairment is required, the ~~allocated portion~~carrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is 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 ~~(headroom) amounting~~cannot be reversed.

Given the nature of Eni’s activities, information on asset fair value is usually difficult to ~~€1,461 million would be reduced to zero under each~~obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by estimating assets’ values-in-use. The valuation is carried out for individual assets or for 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 ~~alternative hypothesis:~~CGUs: (i) ~~a decrease of 69% on average~~ in the ~~projected commercial margins;~~Exploration & Production segment, individual oilfields or pools of oilfields when technical, economic or contractual features make underlying cash flows interdependent; (ii) ~~an increase of 10 percentage points~~ in the ~~discount rate;~~Gas & Power segment, the CGUs 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) ~~a negative nominal growth rate of 19%.~~

~~20 Investments~~

~~Equity-accounted investments~~

(€ million) Book
amount at
the beginning
of the year Additions
and
subscriptions Divestments
and
reimbursements Share of
profit of
equity-
accounted
investments Share of
loss of
equity-
accounted
investments Deduction
for
dividends Changes in
the scope of
consolidation Currency
translation
differences Other
changes Book
amount at
the end
of the year
2015
Investments in
unconsolidated
entities controlled by
Eni 196 8 66 (18) (92) 15 17 (17) 175
Joint ventures 1,269 93 (8) 59 (60) (28) 74 (124) 1,275
Associates 1,707 124 25 (537) (22) 168 (62) 1,403
3,172 225 (8) 150 (615) (142) 15 259 (203) 2,853
2016
Investments in
unconsolidated
entities controlled by
Eni 175 8 10 (8) (2) 5 5 (25) 168
Joint ventures 1,275 1,085 50 (208) (45) 564 12 (58) 2,675
Associates 1,403 63 (138) 17 (154) (53) 29 30 1,197
2,853 1,156 (138) 77 (370) (100) 569 46 (53) 4,040

~~In 2016, additions~~in the Refining & Marketing business line, refining plants, and ~~share capital increases of €1,156 million~~assets related to distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) in the ~~subscription~~Chemical business five lines of ~~the share capital increase of Saipem SpA for €1,069 million.~~

~~Divestments~~activities have been identified as autonomous CGUs: intermediates, polyethylene, styrenes, elastomers and ~~reimbursements of €138 million primarily related to a capital reimbursement of €130 million relating to Angola LNG Ltd.~~biotech activities.

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~~Eni’s share~~As of ~~profit~~2019, following the application of ~~equity-accounted investments~~IFRS 16, the book values of the identified CGUs include the right of use assets (RoU), associated to plants and ~~dividend decrease pertained~~equipment hired in connection with operations at specific CGUs operations. Because they are instrumental 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 according to the ~~following entities:~~

December 31, 2015 December 31, 2016
(€ million) Share of
profit of equity-
accounted
investments Deduction for
dividends Eni’s interest
(%) Share of
profit of equity-
accounted
investments Deduction for
dividends Eni’s interest
(%)
PetroJunín SA 29 40.00 30 40.00
United Gas Derivatives Co 20 21 33.33 14 �� 14 33.33
Gas Distribution Company of Thessaloniki – Thessaly SA 11 8 49.00 10 10 49.00
Eni BTC Ltd 59 90 100.00 6 100.00
Eteria Parohis Aeriou Thessalias AE 5 4 49.00 3 5
Unión Fenosa Gas SA 13 50.00 2 50.00
PetroSucre SA 26.00 30 26.00
Unimar Llc 50.00 16 50.00
Other investments 26 6 12 25
150 142 77 100

~~Eni’s share~~unlevered valuation methodology used for capital projects. Rather, a small number of ~~losses~~RoU not allocated to CGU are considered corporate assets, whose recoverability depends on the whole of ~~equity-accounted investments related~~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 at 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 the associated projections of operating costs and development expenditures. The CGUs of Refining & Marketing, Chemical and Gas & Power, with a definite useful life, (i.e. power plants) are evaluated based on the plant economic and technical life and the associated, normalized projections 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 ~~following entities:~~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.

December 31, 2015 December 31, 2016
(€ million) Share of
loss of equity-
accounted
investments Eni’s interest
(%) Share of
loss of equity-
accounted
investments Eni’s interest
(%)
Saipem SpA 144 30.76
PetroSucre SA 66 26.00 92 26.00
Angola LNG Ltd 469 13.60 62 13.60
PetroBicentenario SA 40.00 26 40.00
CARDÓN IV SA 4 50.00 20 50.00
Matrìca SpA 17 50.00 4 50.00
Newco Tech SpA 5 81.59 4 80.00
Unión Fenosa Gas SA 25 50.00 50.00
Unimar Llc 7 50.00 50.00
Westgasinvest Llc 1 50.01 3 50.01
Other investments 21 15
615 370

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 by major oil companies designed to curtail growth plans to boost shareholders’ returns and lately a shift in the financial approach retained by the U.S. independent producers which have de-emphasized growth to preserve the free cash flow. Based on these considerations and taking into account the ~~outcome~~forecasts made by specialized observatories and investment banks, management has retained its assumption of a long-term Brent crude oil price of 70 $/BBL in real terms 2022, substantially in line with the assumption made in the annual report 2018.

The oversupply condition is even more severe in the gas market due to excess production 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 ~~impairment testing of~~Asian economies and also considering an ongoing switch from coal to gas in the ~~underlying project,~~power generation in Europe. Overall, price assumptions for the ~~book value of the investment~~main gas benchmarks in Petrosucre and the dividends receivable were written off (€65 million). Regarding the projects related to PetroBicentenario and Cardón IV, Eni recorded net losses of €26 million and €20 million, respectively. LossesEurope have been retained at the ~~equity-accounted investment of Angola LNG Ltd of €62 million (€469 million~~same level as the previous planning projections, whilst gas prices assumptions have been revised downward for the reference Henry Hub gas prices in 2015) related to pre-production expenses and operating costs associated with the start-up of the liquefaction plant and an impairment loss of €25 million; in 2015 the amount included impairment charges relating the reduced commodity prices outlook (€433 million).

~~Other negative changes of €53 million related to the impairment of Unión Fenosa Gas SA of €84 million~~USA due to ~~lower profitability prospects.~~

Changes in the scope of consolidation of €569 million include the initial recognition of the retained interest in Saipem SpA of €564 million (and, in addition to this, the subscription pro-quota of the share capital increase for €1,069 million). On January 22, 2016, Eni closed the sale of a 12.503% interest in Saipem to the Italian governmental agency, CDP Equity SpA. Concurrently, a shareholder agreement between Eni and the acquiree entered into force, which established the joint control of the two parties over the target entity. Those transactions triggered loss of control of Eni over Saipem and its derecognition. The retained interest of 30.55% has been recognized as an investment in an equity-accounted joint venture withstructural headwinds.

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~~an initial carrying amount aligned~~Having retained management’s long-term assumptions for crude oil prices unchanged from the previous financial statements, the impairment indicators at the Company’s oil&gas assets were mainly driven by downward reserves revisions and a lowered operating performance.

Furthermore, management is forecasting unchanged spreads for natural gas between the selling prices at Eni’s reference market, Italy, and the spot prices at continental hub to which the gas procurement costs of our long-term contracts are indexed. This latter assumption excludes any evidence of impairment indicator in relation to the ~~share price at~~G&P fixed assets (particularly the ~~closing date~~goodwill recorded in the retail segment).

The Company’s downstream businesses of the ~~transaction (€4.2 per share) recognizing~~refining and the petrochemicals sectors are currently in a ~~loss through profit~~down-cycle due to weak end-demands, excess production capacity and ~~loss~~oversupplies and continuing competitive pressures from overseas operators who can leverage better cost positions and scale economies (for example Middle East refiners and the ethane-based cracking of ~~€441 million. This loss has been recognized in the Group consolidated accounts~~U.S. chemicals producers), while environmental issues are expected to negatively affect consumption and profitability of gasoil and single-use plastics. Operating costs for emission allowances as part of ~~gains~~the European Emission Scheme are also forecast to increase. Furthermore, Eni’s complex refineries have been negatively affected by narrowing price differentials between sour crudes with high sulfur content and ~~losses~~the light benchmark Brent crude, thus impairing the cost-advantage of ~~discontinued operations. At~~complex refineries of processing low-quality crudes that under normal market conditions trade at a discount vs the Brent. Due to those structural weaknesses, management has reduced the profitability outlook of its refineries and petrochemicals plants.

Management tested for impairment the totality of the Group’s fixed assets as provided by the Company’s internal guidelines.

Values-in-use is estimated by discounting post-tax cash flows at a rate, which corresponds for the Exploration & Production segment and Refining & Marketing business line to the Company’s weighted average cost of capital (WACC) net of specific risk factors attributable to the Gas & Power segment and the Chemical business line, the WACC of which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC). Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

In 2019 the weighted-average cost of capital (WACC) to the Group increased marginally from 7.3% in 2018 to 7.4%. Based on our estimation the cost of equity has significantly appreciated driven by a sharp decline in government bond yields in 2019 that lifted the so-called equity risk premium, or the excess return for equities over a risk-free rate of return such as yields on treasuries of benchmark countries like USA and Germany and a step-up in the equity risk premium applied by financial markets to the oil&gas sector reflecting recent underperformance of the sector and uncertainties over future returns considering the structural decline in hydrocarbons prices and the risks associated with the energy transition. However, this impact has been mitigated by a higher leverage following the adoption of the accounting standard IFRS 16 which increased the total finance debt recorded in the balance sheet ~~date,~~and by this way reduced the ~~fair~~increase in the weighted average cost of capital to the Group due to the higher equity risk.

Finally, a weighted-average premium for the country risk is added to the cost of equity; the weighting factor is the amount of invested capital in each country of operations. Calculation of country-specific WACC for each country is obtained by adjusting the Group WACC by the difference between the specific risk premium applicable to a given country and the average country risk premium of the Group portfolio.

Based on those assumptions, the existence of impairment indicators and estimates of discount rates, management recorded the following net impairment losses: (i) in the Exploration & Production segment the Company recorded impairment losses before taxes for €1,217 million driven by downward reserve revisions and lowered future production rates mainly at properties in Congo (WACC at 7.6%), Italy (WACC at 6.4%) and USA (WACC at 6.5%), in this latter country upward estimates of operating costs and expenditures were projected, as well as a loss on the disposal of a property in Ecuador. In the case of an impairment loss higher than €100 million post-tax, a post-tax WACC of 6.4% was applied, corresponding to pre-tax rate of 6.9%; (ii) in the Refining & Marketing business line impairment losses of €819 million were recorded, with the largest amount relating to the Sannazzaro refinery for €684 million driven by the above mentioned revised profitability outlook and also in connection to higher projected costs for CO2 emissions; the remaining amount related to the investments of the year for compliance and stay-in-business made at

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CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review. In the case of an impairment loss higher than €100 million post-tax, a post-tax WACC of 6.6% was applied, corresponding to pre-tax rate of 7.1%; (iii) in the Chemicals business impairment losses amounted to €103 million driven by the deteriorated market outlook described above; and (iv) in the G&P segment, €37 million of impairment losses were recorded at power generation plants in connection to a downward revision to the outlook for electricity margins due to higher competition and overcapacity.

Furthermore, 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. Those projects which have been started in 2019 envisage the purchase of carbon credits certified in accordance with 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 of the segment is observed.

Ultimately, under management’s assumptions for a long-term Brent price at 70$/BBL (real terms 2022), which has remained unchanged for the last few years, and at a reference price for the Italian spot gas benchmark of 7.8$/Mbtu, 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. 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 of the sector: the increased volatility of crude oil prices which have been increasingly exposed to macro and global risks; the continued oversupply in the oil markets which has determined a reset in hydrocarbons realized prices and cash flows of oil companies; growing uncertainty about long-term evolution of the global oil demand in light of the rising commitment on part of the international community at fighting climate change and speeding up the pace of the energy transition, the increase in energy alternatives to fossil fuels and changing consumers’ preferences, management has evaluated the recoverability of the book values of Eni’s oil&gas properties at different stress-test scenarios, including the risk of stranded assets. Particularly, under the toughest of the assumptions at a flat long-term Brent price of 50$/BBL and at a flat Italian gas price of 5$/Mbtu, management is estimating that approximately 85% of the Company’s proven and probable/possible reserves (risked at 70% and 30% respectively) will be produced within 2035 realizing 94% of the overall net present value in the same period. The net present value of those production volumes, valued under the most conservative of the scenarios considered, is substantially aligned with the book values of the net fixed assets of Eni’s ~~investment~~oil&gas properties, including Eni’s share of the fixed assets of our joint ventures like Vår Energi AS, and including in ~~Saipem, corresponding~~the calculation the expected cash outflows committed to the ~~portion~~Company’s forestry projects.

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15 Investments

Equity-accounted investments

	2019								2018
(€ million)	Investments in unconsolidated entities controlled by Eni		Joint ventures		Associates		Total		Investments in unconsolidated entities controlled by Eni		Joint ventures		Associates		Total
Carrying amount – beginning of the year		95		5,497		1,452		7,044		116		2,332		1,063		3,511
Changes in accounting policies (IFRS 9 and 15)												(34)		(3)		(37)
Changes in accounting policies (IAS 28)				22				22
Carrying amount restated – beginning of the year		95		5,519		1,452		7,066		116		2,298		1,060		3,474
Additions and subscriptions		6		76		2,910		2,992				28		92		120
Divestments and reimbursements		(5)				(17)		(22)		(33)		(3)		(115)		(151)
Share of profit of equity-accounted investments		6		80		75		161		8		16		385		409
Share of loss of equity-accounted investments		(10)		(157)		(17)		(184)		(5)		(415)		(10)		(430)
Deduction for dividends		(4)		(1,073)		(61)		(1,138)		(6)		(19)		(25)		(50)
Change in the scope of consolidation		1						1				3,448				3,448
Currency translation differences		2		67		17		86		2		25		54		81
Other changes		(5)		80		(2)		73		13		119		11		143
Carrying amount – end of the year		86		4,592		4,357		9,035		95		5,497		1,452		7,044

In 2019 additions and subscriptions related to: (i) a 20% equity interest in Abu Dhabi Oil Refining Co (Takreer), UAE acquired for a cash consideration of €2,896 million. The investee operates three refineries 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 ~~market capitalization, is higher than~~UAE downstream sector and increases its global refining capacity by 35%, in line with the ~~net book~~Company’s strategy of making Eni’s overall portfolio more geographically diversified and more balanced along the value ~~recorded~~chain; (ii) a capital contribution of €39 million made to Lotte Versalis Elastomers Co Ltd, joint venture operating in ~~Eni’s financial statements. However, considering~~production 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 of Saipem SpA resulted in a gain of €4 million. Considering the volatility of the ~~market environment where~~ Saipem ~~is currently engaging,~~shares and the ongoing uncertainties surrounding a recovery in the investing cycle of oil companies and competitive pressure in the Engineering & Construction segment, management ~~assessed the soundness~~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 ~~by estimating the value in use~~ of the ~~investment based on the projections~~investment.

Share of ~~future earnings and cash flows elaborated by a panel of independent sell-side analysts. That review confirmed the recoverability of the carrying amount.~~

~~The net carrying amount~~losses of equity-accounted investments ~~was~~included a loss of €90 million accounted at the joint venture Cardón IV SA (Eni’s interest 50%) which is operating the Perla gas field 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 million to Vår Energi AS.

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Net carrying amount related to the following ~~entities:~~companies:

	December 31, 2015						December 31, 2016						December 31, 2019				December 31, 2018
(€ million)	Net carrying amount		Number of shares held		Eni’s interest (%)		Net carrying amount		Number of shares held		Eni’s interest (%)		Net carrying amount		% of the investment		Net carrying amount		% of the investment
Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd		96		34,000,000		100.00		106		34,000,000		100.00		30		100.00		31		100.00
Other investments (*)		79						62
Other (*)														56				64
		175						168						86				95
Joint ventures
Saipem								1,497		3,087,679,689		30.76
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		503		273,100		50.00		434		273,100		50.00		326		50.00		335		50.00
PetroJunín SA		174		44,424,000		40.00		211		44,424,000		40.00
CARDÓN IV SA		211		8,605		50.00		197		8,605		50.00
Cardón IV SA														148		50.00		98		50.00
Gas Distribution Company of Thessaloniki – Thessaly SA		109		94,839,500		49.00		150		130,491,508		49.00		139		49.00		137		49.00
Lotte Versalis Elastomers Co Ltd		64		16,520,000		50.00		74		19,200,000		50.00		74		50.00		75		50.00
Unimar Llc		57		50		50.00		42		50		50.00
Eteria Parohis Aeriou Thessalias AE		43		35,652,008		49.00
PetroBicentenario SA		27		40,000		40.00				40,000		40.00
Other investments (*)		87						70
PetroJunín SA														53		40.00		47		40.00
AET – Raffineriebeteiligungsgesellschaft mbH														35		33.33		32		33.33
Other (*)														49				47
		1,275						2,675						4,592				5,497
Associates
Abu Dhabi Oil Refining Co (Takreer)														2,829		20.00
Angola LNG Ltd		1,019		1,591,200,000		13.60		916		1.551.760.000		13.60		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		113		950,000		33.33		117		950,000		33.33		69		33.33		62		33.33
Novamont SpA		77		6,667		25.00		77		6,667		25.00
AET - Raffineriebeteiligungsgesellschaft mbH						33.33		34		1		33.33
PetroSucre SA		123		5,727,800		26.00				5,727,800		26.00
Other investments (*)		71						53
Commonwealth Fusion Systems Llc(a)														37				42
Other (*)														90				73
		1,403						1,197						4,357				1,452
		2,853						4,040						9,035				7,044

(a)

The ownership cannot be determined.

(*)

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

~~Equity-accounted~~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.

Results of equity-accounted investments by segment are disclosed in note 4635 — ~~Information by industry segment~~Segment information and information by geographical area.

~~Carrying~~The carrying amounts of equity-accounted investments included differences between the purchase price of ~~the interest~~ acquired interests and ~~the~~their underlying book value of ~~the corresponding fraction of~~ net ~~equity~~assets amounting to ~~€100~~€72 million, related to Novamont SpA for €43 million and Unión Fenosa Gas SA for ~~€62 million and Novamont SpA for €38~~€29 million. ~~This goodwill is supported~~These surpluses were driven by the long-term profitability outlook of the acquired ~~companies.~~companies at the time of the acquisition.

As of December 31, ~~2016,~~2019, the market value of the investments listed in regulated stock markets was as follows:

Number of
shares held Eni’s interest
(%) Share price
(€) Market value
(€ million)
Saipem SpA 3,087,679,689 30.76 0.535 1,652

	Saipem SpA
Number of shares held		308,767,968
% of the investment		30.99
Share price (€)		4.356
Market value (€ million)		1,345
Book value (€ million)		1,250

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The table below sets out the provisions for losses included in the provisions for contingencies of €151 million (€126 million at December 31, 2015), primarily related to the following equity-accounted investments:

(€ million) December 31,
2015 December 31,
2016
Industria Siciliana Acido Fosforico – ISAF – SpA
(in liquidation) 93 95
VIC CBM Ltd 10 34
Société Centrale Eletrique du Congo SA 8 7
Agip Oleoducto de Crudos Pesados BV 7
PetroBicentenario SA 6
Polimeri Europa Elastomeres France SA 8
Other investments 7 2
126 151

Additional information is included in note 4837 — Other information about investments.

Other investments

(€ million) Net book
amount at
the beginning
of the year Additions Divestments
and
reimbursements Valuation
at fair value Currency
translation
differences Other
changes Value at
the end
of the year Gross book
amount at
the end
of the year Accumulated
impairment
charges
2015
Investments in unconsolidated entities controlled by Eni 14 3 8 25 26 1
Associates 12 1 (3) 10 10
Other investments:
- valued at fair value 1,744 (1,425) 49 368 368
- valued at cost 245 (10) 21 1 257 260 3
2,015 3 (1,435) 49 22 6 660 664 4
2016
Investments in unconsolidated entities controlled by Eni 25 5 (1) 29 30 1
Associates 10 3 (2) (1) 10 10
Other investments
- valued at fair value 368 (368)
- valued at cost 257 (31) 6 5 237 240 3
660 8 (399) 4 3 276 280 4

(€ million)	2019		2018
Carrying amount – beginning of the year		919		219
Changes in accounting policies (IFRS 9)				681
Carrying amount restated – beginning of the year		919		900
Additions and subscriptions		11		5
Change in the fair value		(3)		15
Divestments and reimbursements		(12)		(22)
Currency translation differences		15		31
Other changes		(1)		(10)
Carrying amount – end of the year		929		919

~~Divestments and reimbursements of the investments valued at~~The fair value of ~~€368 million related~~ the ~~sale of 2.22% interest~~main non-controlling interests in ~~Snam SpA through: (i) exercise~~non-listed investees on regulated markets, classified within level 3 of the ~~conversion right by~~fair value hierarchy, was estimated based on a methodology that combines future expected earnings and the ~~holders~~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 ~~convertible bonds~~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 primarily related to ~~76,888,264 shares, representing approximately 2.2%~~Nigeria LNG Ltd for €657 million (€651 million at December 31, 2018) and Saudi European Petrochemical Co “IBN ZAHR” for €146 million (€144 million at December 31, 2018).

16 Other financial assets

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

Financing receivables are stated net of allowance for doubtful accounts as follows:

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

Financing receivables held for operating purposes related principally to funds provided to joint ventures and associates in the ~~share~~Exploration & Production segment (€1,041 million) and the Gas & Power segment (€49 million) to execute capital ~~for a total consideration~~projects of ~~€332 million corresponding~~interest to ~~a price~~Eni. These receivables are expression of ~~��4.32 per share and a loss recognized in profit and loss of €32 million; (ii) sale of the remaining 792,619 shares on the open market for a consideration of €4 million.~~

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~~The net carrying amount of other investments of €276 million (€660 million at December 31, 2015) was related to~~long-term interests in the ~~following entities:~~

December 31, 2015 December 31, 2016
(€ million) Net carrying
amount Number of
shares held Eni’s interest
(%) Net carrying
amount Number of
shares held Eni’s interest
(%)
Investments in unconsolidated entities controlled by Eni (*) 25 29
Associates 10 10
Other investments:
- Nigeria LNG Ltd 109 118,373 10.40 112 118,373 10.40
- Darwin LNG Pty Ltd 60 213,995,164 10.99 49 213,995,164 10.99
- Snam SpA 368 77,680,883 2.22
- other(*)
88 76
625 237
660 276

~~(*)~~

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

~~Additional information is included in note 48 — Other information about investments.~~

~~21 Other financial assets~~

(€ million) December 31, 2015 December 31, 2016
Receivables held for operating purposes 949 1,785
Securities held for operating purposes 77 75
1,026 1,860

~~Financing receivables held for operating purposes are stated net of the valuation allowance for doubtful accounts of €480 million (€347 million at December 31, 2015).~~

(€ million) Amount at
December 31,
2015 Additions Currency
translation
differences Amount at
December 31,
2016
Reserve of allowance for doubtful accounts of financing receivables 347 121 12 480

Financing receivables held for operating purposes of €1,785 million (€949 million at December 31, 2015) primarily pertained to loans granted by the Exploration & Production segment (€1,471 million), the Gas & Power segment (€133 million) and Refining & Marketing and Chemical segment (€109 million).

~~Financing receivables granted to joint ventures and associates amounted to €1,350 million (€396 million at December 31, 2015).The~~initiatives funded. The greatest exposure is towards the joint venture ~~CARDÓN~~Cardón IV SA (Eni’s interest 50%) in Venezuela, which is currently operating ~~and developing~~ the Perla offshore gas field. Due to a deteriorated financial outlook of PDVSA and the continuing refinancing of the outstanding loan granted by Eni to the joint venture, the relevant operating financing receivable was reclassified to non-current assets and, as of December 31, 2016, the recoverability was assessed based on the outcome of the impairment review of the underlying industrial project. At December 31, 2016, Eni’s exposure towards the joint venture amounted to €1,054 million (€1,112 million at 31 December 2015). The receivable is accruing interest income at a rate equal to Libor plus 700 basis points as provided by the agreement between Eni and Cardón IV, which were approved by Eni’s Board of Directors with a cap to the financing up to $1.5 billion. The loan will be repaid through the cash flows generated by the gas produced by the field, ~~and supplied to the Venezuelan State-owned company, PDVSA, on the base of a gas sale agreement expiring in 2036.~~

In assessing the recoverability of the financing receivable granted to the joint venture Cardón IV, management has evaluated that the loan approximates the provision of equity capital, and its recoverability mainly depends upon the capacity of the joint venture to pay down the loan with its cash flows from

~~F-54~~

~~TABLE OF CONTENTS~~

operations. Therefore, the recoverability of the financing receivable has been assessed based on the present value of the project future cash flows, as part of the project impairment review, discounted by using the Eni’s WACC for Venezuela, which takes into account the business risk and the country risk. The project VIU was then compared to the sum of the book values of Eni’s interest in Cardón IV and of the financing receivable with the VIU exceeding the assets book values. Furthermore, given the counterparty risk considering the deteriorated financial situation in Venezuela, the value-in-use has been stress-tested assuming either: i) a two-year delay in the payment of gas supplies to the joint venture by PDVSA; ii) the collection of proceeds on only 70% of the gas sales in line with the current securitization agreements. Under both of these scenarios, the value-in-use retained a headroom over the assets book values.

Allowances for doubtful accounts of financing receivables of €121 million included an impairment for €93 million of a financing receivable granted to Matrìca SpA (Eni’s share 50%), a joint venture with Novamont SpA for the production of chemical products from renewable sources, to reflect the repayment capacity of the venture considering the industrial risks of the project.

~~Financing receivables held for operating purposes in currencies other than euro amounted to €1,606 million (€649~~€563 million at December 31, ~~2015)~~2019 (€705 million at December 31, 2018).

Financing receivables held for operating purposes due beyond five years amounted to ~~€1,519~~€1,018 million (€~~623~~1,088 million at December 31, ~~2015)~~2018).

The ~~valuation at~~ fair value of non-current financing receivables held for operating purposes of ~~€1,799~~€1,119 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from ~~-0.2%~~-0.3% to ~~2.6% (0%~~2.0% (-0.2% and ~~2.7%~~2.9% at December 31, ~~2015)~~2018).

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 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, 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 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 million and €1,112 million, respectively.

Securities ~~of €75 million (€77 million at December 31, 2015), designated as held-to-maturity investments, are~~held for operating purposes related to listed bonds issued by sovereign ~~states~~states.

Securities for ~~€71~~€20 million ~~(€70 million~~(same amount at December 31, ~~2015) and~~2018) were pledged as guarantee of the deposit for gas cylinders as provided for by the ~~European Investment Bank for €4 million (€7 million at December 31, 2015).~~Italian law.

The following table analyses securities per issuing entity:

Amortized
cost
(€ million) Nominal
value
(€ million) Fair
Value
(€ million) Nominal
rate of
return (%) Maturity
date Rating -
Moody’s Rating -
S&P
Sovereign states
Fixed rate bonds
Italy 24 24 26 from 0.45 to 4.75 from 2017 to 2025 Baa2 BBB-
Spain 15 14 15 from 1.40 to 4.30 from 2019 to 2020 Baa2 BBB+
Ireland 9 8 9 from 4.40 to 4.50 from 2018 to 2019 A3 A+
Iceland 3 3 3 2.50 2020 A3 BBB+
Poland 3 2 3 4.20 2020 A2 BBB+
Slovenia 2 2 2 4.13 2020 Baa3 A
Belgium 2 2 2 1.40 2018 Aa3 AA
Floating rate bonds
Italy 11 11 11 from 2018 to 2019 Baa2 BBB-
Mozambique 2 2 2 from 2017 to 2019 Caa3 B-
Total sovereign states 71 68 73
European Investment
Bank 4 4 4 2018 Aaa AAA
75 72 77

Amortized
cost
(€ million)

Nominal
value
(€ million)

Fair
Value
(€ million)

Nominal
rate of
return (%)

Maturity
date

Rating-
Moody’s

Rating-
S&P

Sovereign states

Fixed rate
bonds

Italy

from 0.20 to 4.75

from 2020 to 2025

Baa3

BBB

Others (*)

from 0.05 to 4.20

from 2020 to 2024

from Aa3 to Baa1

from AA to A-

Floating rate bonds

Italy

from 2020 to 2022

Baa3

BBB

Others

2022

Baa3

BBB

Total sovereign states

~~Securities~~

(*)

Amounts included herein are lower than €10 million.

All securities have a maturity within five ~~years (beyond five years for €1 million at December 31, 2015).~~years.

The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in note 4736 — Transactions with related parties.

~~F-55~~F-60

TABLE OF CONTENTS

~~22 Deferred tax assets~~

~~Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for €4,286 million (€3,355 million at December 31, 2015).~~

(€ million) Amount at
December 31,
2015 Additions Deductions Currency
translation
differences Other
changes Amount at
December 31,
2016
Deferred tax assets 8,952 2,994 (1,208) 185 (1,511) 9,412
Provisions for impairments (5,099) (667) 254 (80) (30) (5,622)
3,853 2,327 (954) 105 (1,541) 3,790

Deferred tax assets related for €1,690 million (€1,911 million at December 31, 2015) to the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes. Those assets were recorded on the pre-tax loss of the year and on the recognition of deferred deductible expenses within the limits of the amounts expected to be recovered in future years based on availability of expected future taxable profit.

~~Additions to the impairment provision of €667 million were explained by projections of lower future taxable profit at Italian subsidiaries (€433 million).~~

~~Deferred tax assets are further described in note 32 — Deferred tax liabilities.~~

~~Income taxes are described in note 43 — Income taxes.~~

~~23 Other non-current assets~~

(€ million) December 31, 2015 December 31, 2016
Tax receivables from:
- Italian tax authorities
- income tax 44 73
- interest on tax credits 63 64
107 137
- non-Italian tax authorities 287 365
394 502
Other receivables:
- related to divestments 567 222
- other non-current 46 52
613 274
Fair value of derivative financial instruments 218 108
Other asset 533 464
1,758 1,348

Receivables from divestments amounted to €222 million (€567 million at December 31, 2015) and included the long-term portion of €166 million (€463 million at December 31, 2015) of a receivable related to the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunayGas in 2008 based on the agreements defined between the international partners of the North Caspian Sea PSA and the Kazakh government, which enacted a new contractual framework and a new setup for managing project operations. The repayment of the first of the three installments of the receivable took place in the fourth quarter of 2016 with the achievement of the agreed target production level. The receivable accrues interest income at market rates. The current portion of the receivable is indicated in note 11 —17 Trade and other ~~receivables.~~payables

The ~~fair value related to derivative financial instruments~~following are the effects of the application 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 of IFRS 16 is disclosed in note 343 — ~~Derivative financial instruments.~~

Changes in accounting policies.

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

~~F-56~~

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

~~TABLE OF CONTENTS~~

Other non-current assets amounted to €464 million (€533 million at December 31, 2015), of which €113 million (€277 million at December 31, 2015) were deferred costs of take-or-pay gas volumes in connection with the Company’s long-term supply contracts. The amount was recognized due to the obligation to pay the contractual priceBecause of the ~~volumes~~short-term maturity and conditions of ~~gas, which~~remuneration of trade and other payables, the ~~Company failed to collect up to~~fair values approximated the minimum contractual take in previous reporting periods in order to fulfill the take-or-pay clause provided by the relevant long-term supply contracts. The Company is entitled to off-take the prepaid volumes in future years alongside contract execution, up to contract expiration or in a shorter term as the case may be. Those deferred costs, which are equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-year impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. In 2016, based on this accounting, an impairment of €31 million was recorded. The reduction in the amount of the deferred costs at the reporting date compared to 2015 wascarrying amounts.

Payables due to the reclassification to other current assets of volumes expected to be recovered by 2017 (€133 million). A portion of the deferred costs has remained classified non-current, because the Company plans to lift the prepaid quantities beyond the term of 12 months. In spite of weak market conditions in the European gas sector due to sluggish demand growth and strong competitive pressures fuelled by oversupplies, management plans to recover volumes underlying the deferred cost within the plan horizon.

~~Transactions with~~ related parties are described in note 4736 — Transactions with related parties.

~~Current liabilities~~18 Finance debts

	December 31, 2019								December 31, 2018
(€ million)	Short-term debt		Current portion of long-term debt		Long-term debt		Total		Short-term debt		Current portion of long-term debt		Long-term debt		Total
Banks		187		504		2,341		3,032		383		768		2,710		3,861
Ordinary bonds				2,642		16,137		18,779				2,781		16,923		19,704
Convertible bonds						393		393						390		390
Commercial papers		1,778						1,778		915						915
Other financial institutions		487		10		39		536		884		52		59		995
		2,452		3,156		18,910		24,518		2,182		3,601		20,082		25,865

~~24 Short-term debt~~

(€ million) December 31, 2015 December 31, 2016
Commercial papers 4,962 2,738
Banks 142 155
Other financial institutions 616 503
5,720 3,396

~~The decrease in short-term debt~~Finance debts decreased of ~~€2,324~~€1,347 million ~~primarily related~~due to repayments made net ~~reimbursements for €2,645~~of new issuance of €1,540 million and ~~as increase,~~increased due to currency translation differences relating to foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for ~~€452~~€249 million.

Commercial papers ~~of €2,738 million (€4,962 million at December 31, 2015)~~ were issued by the Group’s financial ~~subsidiaries Eni Finance USA Inc for €1,750 million (€2,189 million at December 31, 2015) and Eni Finance International SA for €988 million (€2,773 million at December 31, 2015).~~

~~The breakdown by currency of short-term debt is provided below:~~

(€ million) December 31, 2015 December 31, 2016
Euro 3,056 1,405
U.S. dollar 2,616 1,982
Other currencies 48 9
5,720 3,396

~~As of December 31, 2016, the weighted average interest rate on short-term debt was 0.9% (0.6% as of December 31, 2015).~~

As of December 31, 2016, Eni retained undrawn committed and uncommitted borrowing facilities amounting to €41 million and €12,267 million, respectively (€40 million and €12,708 million at December 31, 2015, respectively). Those facilities bore interests and charges for undrawn that reflect prevailing market conditions.

~~As of December 31, 2016, Eni did not report any default on covenants or other contractual provisions in relation to borrowing facilities.~~subsidiaries.

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TABLE OF CONTENTS

~~Because~~The following table reflects long-term debt as of ~~the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.~~

~~Payables due to related parties are described in note 47 — Transactions with related parties.~~

~~25 Trade and other payables~~

(€ million) December 31, 2015 December 31, 2016
Trade payables 9,605 11,038
Advances 637 526
Other payables
- related to capital expenditures 1,884 2,158
- others 2,816 2,981
4,700 5,139
14,942 16,703

~~The increase in trade payables amounting to €1,433 million primarily related to the Gas & Power segment (€985 million).~~

~~Down payments and advances for €526 million (€637 million at~~ December 31, 2015) related to the Refining & Marketing business line for €263 million (€253 million at December 31, 2015) and to the Exploration & Production segment for €153 million (€71 million at December 31, 2015).

~~Other payables were as follows:~~

(€ million) December 31, 2015 December 31, 2016
Payables related to capital expenditures due to
Suppliers in relation to investing activities 1,544 1,835
Joint venture operators in exploration and production activities 283 219
Other 57 104
1,884 2,158
Other payables
Joint venture operators in exploration and production activities 1,750 2,057
Employees 207 180
Social security entities 100 94
Non-financial government entities 5 6
Other 754 644
2,816 2,981
4,700 5,139

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

~~Payables due to related parties are described in note 47 — Transactions with related parties.~~

~~26 Income tax payable~~

(€ million) December 31, 2015 December 31, 2016
Italian subsidiaries 65 97
Non-Italian subsidiaires 366 329
431 426

~~Income tax payable is described in note 43 — Income taxes.~~

~~F-58~~

~~TABLE OF CONTENTS~~

~~27 Other tax payable~~

(€ million) December 31, 2015 December 31, 2016
Excise and customs duties 716 634
Other taxes and duties 738 659
1,454 1,293

~~28 Other current liabilities~~

(€ million) December 31, 2015 December 31, 2016
Fair value of derivatives financial instruments 4,261 2,108
Other liabilities 451 491
4,712 2,599

~~Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.~~

Other current liabilities of €491 million (€451 million at December 31, 2015) included the current portion of advances received from Suez following a long-term agreement for supplying natural gas and electricity for €73 million (€76 million at December 31, 2015). Non-current portion is disclosed in note 33 — Other non-current liabilities.

~~Advances cashed in~~2019 by gas customers were utilized in 2016 for €10 million (versus €11 million at the opening balance). Those customers off-took lower volumes than the contractual minimum take provided by the relevant long-term supply contract in previous reporting periods, paying Eni the relevant cash advance.maturity:

~~Transactions with related parties are described in note 47 — Transactions with related parties.~~

~~Non-current liabilities~~

~~29 Long-term debt and current portion of long-term debt~~

At December 31, Long-term maturity
(€ million) Maturity
range 2015 2016 Current
maturity
2017 2018 2019 2020 2021 After Total
Banks 2017 – 2032 3,920 4,286 272 864 1,485 484 341 840 4,014
Ordinary bonds 2017 – 2043 17,608 19,003 2,959 1,168 2,503 2,422 940 9,011 16,044
Convertible bonds 2022 339 383 383 383
Other financial institutions 2017 – 2031 206 171 48 48 50 3 3 19 123
22,073 23,843 3,279 2,080 4,038 2,909 1,284 10,253 20,564

Long-term debt and current portion of long-term debt of €23,843 million (€22,073 million at December 31, 2015) increased by €1,770 million. The increase comprised new issuance of €4,202 million net of repayments made for €2,323 million and, as decrease, currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €28 million.

~~Debt due to other financial institutions of €171 million (€206 million at December 31, 2015) included €29 million of finance lease transactions (€26 million at December 31, 2015).~~

	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 ~~maintenance~~retention of ~~certain financial ratios based on the Consolidated Financial~~

~~F-59~~

~~TABLE OF CONTENTS~~

~~Statements of Eni or~~ a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees ~~would~~could be required to be agreed upon with the European Investment Bank. In addition, Eni entered into ~~long and medium-term~~long-term facilities subject to the retention of certain financial ratios based on the Consolidated Financial Statements of Eni with Citibank Europe ~~Plc providing for conditions similar to those applied by~~Plc. In case of default, the ~~European Investment Bank.~~bank may request early repayment. At December 31, ~~2016,~~2019, debts subjected to restrictive covenants amounted to ~~€1,953~~€1,243 million (€~~2,127~~1,337 million at December 31, ~~2015)~~2018). Eni ~~complied~~was in compliance with those covenants.

Ordinary bonds ~~of €19,003 million (€17,608 million at December 31, 2015)~~ consisted of bonds issued within the Euro Medium Term Notes Program for a total of ~~€16,528~~€15,030 million and other bonds for a total of ~~€2,475~~€3,749 million.

The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, ~~2016:~~2019:

	Amount		Discount on bond issue and accrued expense		Total		Currency		Maturity					Rate %
(€ million)										Amount		Discount on bond issue and accrued expense			Total			Currency		Maturity				Rate %
(€ million)	Amount		Discount on bond issue and accrued expense		Total		Currency			Amount		Discount on bond issue and accrued expense			Total			Currency		Amount		Discount on bond issue and accrued expense		Total		Currency		from		to		from		to		from	to	from	to
Issuing entity																				Amount		Discount on bond issue and accrued expense		Total		Currency
Euro Medium Term Notes
Eni SpA		1,500		15		1,515		EUR					2019						4.125		1,200		16		1,216		EUR				2025				3.750
Eni SpA		1,250		6		1,256		EUR					2017						4.750		1,000		38		1,038		EUR				2020				4.250
Eni SpA		1,200		17		1,217		EUR					2025						3.750		1,000		28		1,028		EUR				2029				3.625
Eni SpA		1,000		36		1,036		EUR					2020				��		4.250		1,000		20		1,020		EUR				2020				4.000
Eni SpA		1,000		31		1,031		EUR					2018						3.500		1,000		10		1,010		EUR				2023				3.250
Eni SpA		1,000		26		1,026		EUR					2029						3.625		1,000		8		1,008		EUR				2026				1.500
Eni SpA		1,000		19		1,019		EUR					2020						4.000		900		(4)		896		EUR				2024				0.625
Eni SpA		1,000		6		1,006		EUR					2026						1.500		800		2		802		EUR				2021				2.625
Eni SpA		1,000		6		1,006		EUR					2023						3.250		800		(1)		799		EUR				2028				1.625
Eni SpA		900		(7)		893		EUR					2024						0.625		750		9		759		EUR				2024				1.750
Eni SpA		800		1		801		EUR					2021						2.625		750		5		755		EUR				2027				1.500
Eni SpA		800		(3)		797		EUR					2028						1.625		750		(4)		746		EUR				2034				1.000
Eni SpA		750		13		763		EUR					2019						3.750		700		2		702		EUR				2022				0.750
Eni SpA		750		6		756		EUR					2024						1.750		650		3		653		EUR				2025				1.000
Eni SpA		700				700		EUR					2022						0.750		600		(4)		596		EUR				2028				1.125
Eni SpA		600		(6)		594		EUR					2028						1.125
Eni Finance International SA																					1,558		(3)		1,555		USD		2026		2027				variable
Eni Finance International SA		527		14		541		GBP			2018		2021			4.750			6.125		295		4		299		EUR		2028		2043		3.875		5.441
Eni Finance International SA		395		5		400		EUR			2017		2043			3.750			5.441		118		5		123		GBP				2021				4.750
Eni Finance International SA		170		1		171		YEN			2019		2037			1.955			2.810		25				25		YEN				2021				1.955
		16,342		186		16,528															14,896		134		15,030
Other bonds
Eni SpA		1,109		10		1,119		EUR					2017						4.875		890		4		894		USD				2023				4.000
Eni SpA		427		3		430		USD					2020						4.150		890		2		892		USD				2028				4.750
Eni SpA		333				333		USD					2040						5.700		890		(1)		889		USD				2029				4.250
Eni SpA		215		1		216		EUR					2017						variable		401		4		405		USD				2020				4.150
Eni SpA																					312		1		313		USD				2040				5.700
Eni USA Inc		379		(2)		377		USD					2027						7.300		356				356		USD				2027				7.300
		2,463		12		2,475															3,739		10		3,749
		18,805		198		19,003															18,635		144		18,779

As of December 31, ~~2016,~~2019, ordinary bonds maturing within 18 months ~~of €3,724 million were issued by Eni SpA for €3,622 million and by Eni Finance International SA for €102~~amounted to €2,611 million. During ~~2016, Eni SpA issued~~2019, new bonds ~~for €2,984~~issued amounted to €1,635 million.

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The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, ~~2016:~~2019:

(€ million) Amount Discount on
bond issue
and accrued
expense Total Currency Maturity Rate%
Issuing entity
Eni SpA 400 (17) 383 EUR 2022 0.000
400 (17) 383

(€ million)

Amount

Discount on
bond issue
and accrued
expense

Total

Currency

Maturity

Rate %

Eni SpA

400

(7)

393

EUR

2022

0.000

~~In 2016, Eni issued a~~The non-dilutive equity-linked bond provides for ~~a total nominal value of €400 million with~~ a redemption value linked to the market price of Eni’s shares. The bondholders ~~will~~ have “conversion” rights at certain times and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, ~~the issue and the conversion of the bonds will not give right~~ to ~~any share of Eni and there will be no dilution for shareholders. To~~ hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The bonds will have a six-year maturity and will pay no interest and, accordingly, the coupon will be equal to 0%. The bonds were issued at a price equal to 100.5% of par and will be redeemed at par at maturity, unless previously converted or redeemed under their terms. The initialbond conversion price ~~for the bonds has been set at €17.6222, representing~~is equal €17.62 and includes a 35% premium ~~above~~with respect to the Eni’s share reference price at the date of €13.0535 determined as the arithmetic average of the daily volume-weighted average prices of an ordinary share of Eni on the Milan Stock Exchange over a period of seven consecutive scheduled trading days starting from 7 April 2016. The settlement and closing took place on 13 April 2016.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.

The bond convertible into ordinary shares of Snam SpA, amounting to €339 million as of 31 December 2015, expired on 18 January 2016. Following the exercise of the conversion rights, Eni delivered to the bondholders 76,888,264 shares ordinary representing approximately 2.20% of the share capital of Snam SpA. The residual bonds, amounting to €3.4 million, for which it was not exercised the conversion rights, were redeemed for cash.

~~The following table provides a breakdown by currency of long-term debt, its current portion and the related weighted average interest rates.~~

December 31,
2015
(€ million)

Average rate
(%)

December 31,
2016
(€ million)

Average rate
(%)

Euro 19,623 3.2 21,545 2.7
U.S. dollar 1,660 5.0 1,587 5.2
British pound 629 5.3 540 5.3
Japanese yen 161 2.6 171 2.6
22,073 23,843

As of December 31, 2016, Eni retained undrawn long-term committed borrowing facilities of €6,236 million (€6,577 at December 31, 2015), of which €700 million due in 2017. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. As of 31 December 2016, Eni did not utilize any of its currently committed long-term borrowing facilities (€1 million at December 31, 2015) considering the amount of the liquidity reserves retained by the Company.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which ~~€16.3~~€14.9 billion were drawn as of December 31, ~~2016.~~2019.

The ~~Group has credit ratings~~following table provides a breakdown by currency of ~~BBB+ outlook stable~~finance debt and ~~A-2, respectively for long~~the related weighted average interest rates:

	December 31, 2019								December 31, 2018
	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
U.S. dollar		1,981		2.3		5,392		4.6		1,007		2.5		4,530		4.3
Other currencies		7		(0.7)		148		4.3		495		1.0		518		4.2
		2,452				22,066				2,182				23,683

As of December 31, 2019, Eni retained undrawn uncommitted borrowing facilities amounting to €13,299 million (€12,484 million at December 31, 2018) and short-term debt, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked to the Company’s industrial fundamentals and trendsundrawn long-term committed borrowing facilities of €4,667 million (€5,214 million at December 31, 2018). Those facilities bore interest rates reflecting prevailing conditions in the ~~trading environment~~marketplace. As of December 31, 2019, Eni was in compliance with covenants and other contractual provisions in ~~addition,~~relation to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni.borrowing facilities.

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~~TABLE OF CONTENTS~~

Fair value of long-term debt, including the current portion of long-term debt ~~amounted to €25,358 million (€23,899 million at December 31, 2015):~~is described below:

(€ million)	December 31, 2015		December 31, 2016		December 31, 2019		December 31, 2018
Ordinary bonds		18,984		20,501		19,173		20,257
Convertible bonds		341		435		402		399
Banks		4,356		4,244		2,904		3,445
Other financial institutions		218		178		49		111
		23,899		25,358		22,528		24,212

Fair value of ~~financial debt~~finance debts was calculated by discounting the expected future cash flows at discount rates ranging from ~~-0.2%~~-0.3% to ~~2.6% (0%~~2.0% (-0.2% and ~~2.7%~~2.9% at December 31, ~~2015)~~2018).

~~At December 31, 2016, Eni did not pledge restricted deposits as collateral against its borrowings.~~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

Other non-monetary changes include €668 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

19 Information on net borrowings

In assessing its capital structure, Eni uses 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 ~~as endorsed by IASB~~ less: cash and cash equivalents, held-for-trading securities and ~~other financial assets, and~~ certain ~~highly liquid~~highly-liquid investments not related to operations including, among others, non-operating financing ~~receivables and available-for-sale securities not related to operations.~~receivables. Held-for-trading securities ~~and other financial assets~~ 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. ~~Available-for-sale securities not related to operations consist primarily of government bonds and securities from financing institutions.~~ 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. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt

	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

Cash and ~~shareholders’ equity is well balanced according to industry standards~~cash equivalent are disclosed in note 5 — Cash and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate 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 that of other companies.cash equivalent.

December 31, 2015 December 31, 2016
(€ million) Current Non-
current Total Current Non-
current Total
A. Cash and cash equivalents 5,209 5,209 5,674 5,674
B. Held-for-trading financial assets 5,028 5,028 6,166 6,166
C. Available-for-sale financial assets 238 238
D. Liquidity (A+B+C) 10,237 10,237 12,078 12,078
E. Financing receivables 685 685 385 385
F. Short-term debt towards banks 142 142 155 155
G. Long-term debt towards banks 455 3,465 3,920 272 4,014 4,286
H. Bonds 2,176 15,771 17,947 2,959 16,427 19,386
I. Short-term debt towards related parties 208 208 191 191
L. Other short-term liabilities 5,370 5,370 3,050 3,050
M. Other long-term liabilities 45 161 206 48 123 171
N. Total borrowings (F+G+H+I+L+M) 8,396 19,397 27,793 6,675 20,564 27,239
O. Net borrowings (N-D-E) (2,526) 19,397 16,871 (5,788) 20,564 14,776

~~F-62~~

~~TABLE OF CONTENTS~~

Financial assets held for trading ~~of €6,166 million (€5,028 million at December 31, 2015) related to Eni SpA for €6,062 and to Eni Insurance DAC for €104 million. For further information see~~are disclosed in note 96 — Financial assets held for trading.

~~Available-for-sale securities of €238~~Financing receivables are disclosed in note 16 — Other financial assets.

Finance debts are disclosed in note 18 — Finance debts.

Liabilities for leased assets related for €1,976 million were held for non-operating purposes and related to Eni Insurance DAC. Furthermore, Eni held certain held-to-maturity and available-for-sale securities destined to operating purposes amounting to €75 million (€359 million at December 31, 2015). These securities are excluded from the calculation above. The decrease of €282 million was mainly due to the ~~reclassification~~share of ~~securities retained~~joint operators in upstream projects operated by Eni Insurance DAC to securities held for non-operating purposes. In previous reporting periods, those securities were committed to fund the loss reserve of the insurance company. The change in the destination of those assets was permitted by the entry into force from January 1, 2016, of the provisions of EU Solvency II Directive on capital requirements towhich will be ~~met for operating in the insurance activity.~~recovered through a partner cash-call billing process. More information is reported in note 1012 — ~~Financial~~Right-of-use assets ~~available for sale.~~and lease liabilities.

Current financing receivables of €385 million (€685 million at December 31, 2015) were held for non-operating purposes. At the reporting date, the Company held financing receivables which were destined to operating purposes amounting to €158 million (€1,622 million at December 31, 2015), of which €28 million (€1,135 million at December 31, 2015) were in respect of financing granted to joint ventures and affiliates which executed capital projects and investments on behalf of Eni’s Group companies. The decrease of €300 million was mainly due to the repayment of receivables related to margins on derivatives of Eni Trading & Shipping SpA for €457 million and, as increase, the reclassification to financial receivables of €287 million as a consequence of the adoption starting from January 1, 2016, of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale.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, 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

30 Provisions for ~~contingencies~~

(€ million) Carrying
amount at
December 31,
2015 New or
increased
provisions Initial
recognition
and
changes in
estimates Accretion
discount Utilization Reversal
of unutilized
provisions Currency
translation
differences Other
changes Carrying
amount at
December 31,
2016
Provision for
decommissioning and social
projects 8,998 (647) 297 (336) (1) 55 53 8,419
Environmental provision 2,737 235 8 (249) (37) (3) 2,691
Provision for litigations 1,725 177 (1,099) (25) 1 175 954
Provision for taxes 484 258 (30) (2) 21 1 732
Loss adjustments and
actuarial provisions for Eni’s
insurance companies 323 52 (184) 16 207
Provision for redundancy incentives 201 1 3 (13) (8) (8) 176
Provision for onerous contracts 273 6 3 (103) (6) (7) (1) 165
Provision for losses on investments 128 41 (11) 2 (7) 153
Provision for OIL insurance
cover 72 16 88
Provision for disposal and restructuring 80 7 (16) (11) (2) 58
Provision for green certificates 190 (13) (1) (175) 1
Other (*)
164 213 1 (72) (7) 4 (51) 252
15,375 1,006 (647) 312 (2,115) (109) 74 13,896

~~(*)~~

~~Each individual amount included herein was lower than €50 million.~~

~~The Group makes full provision for~~site restoration, abandonment and social projects include the ~~future costs~~present value of ~~decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The decommissioning provisions at~~ the ~~reporting date amounted to €8,419 million and included future costs for social projects. Those provisions comprised the discounted~~ estimated costs that the Company expects to incur for

~~F-63~~

~~TABLE OF CONTENTS~~

decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration of the

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TABLE OF CONTENTS

Exploration & Production segment for ~~€7,901~~€8,411 million. ~~Negative estimates’ revisions~~Initial recognitions and changes in estimates of ~~€647~~€2,074 million were ~~primarily due to~~mainly driven by a ~~rise~~decrease in the discount rate curve ~~in particular for the U.S. dollar~~ and to a lesser extent by the ~~revision~~recognition of ~~previous estimates of~~new decommissioning ~~costs, partially offset by new provisions~~obligations due to the activity of the year. The ~~accretion~~unwinding of discount recognized ~~in the~~through profit and loss ~~account~~ for ~~€297~~€247 million was determined ~~by adopting~~based on discount rates ranging from -0.1% to 6.1% (from ~~-0.01%~~-0.2% to ~~5.8% (from 0.2% to 4.6%~~6.1% at December 31, ~~2015)~~2018). Main expenditures associated with decommissioning operations are expected to be incurred over a ~~40-year~~45-year period.

Provisions for environmental risks ~~of €2,691 million~~ included the estimated costs for environmental ~~remediation~~clean-up and ~~restoration~~remediation of soil and groundwater in areas owned or under concession where the Group ~~conducted~~performed in the past industrial operations ~~which~~that were progressively divested, shut down, dismantled or restructured. The provision ~~has been~~was accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out ~~cleaning-up operations~~environmental clean-up and remediation and the expected costs can be estimated reliably. The provision ~~includes~~included the expected charges associated with strict liability related to obligations of ~~restoring the contaminated sites~~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 ~~of third~~borne by other operators when the Company acquired or otherwise took over ~~the ownership of the site.~~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 ~~perform~~performing certain cleaning-up and restoration projects and a reliable cost estimation is available. At December 31, ~~2016,~~2019, environmental provision primarily related to Eni Rewind SpA (former Syndial ~~SpA~~SpA) for ~~€2,211~~€1,930 million and to the Refining & Marketing business line for ~~€364 million. Additions~~€416 million which includes the costs of ~~€235 million primarily related to Syndial SpA~~restoration and environmental remediation as a part of the Memorandum of Understanding signed between Eni and the Ministry for ~~€110 million and to~~ the ~~Refining & Marketing business line for €99 million. Utilizations of €249 million primarily related to the Refining & Marketing business line for €124 million Syndial SpA for €89 million.~~Environment in December 2019.

~~Provisions for litigations of €954 million~~Litigation provisions comprised ~~the~~ expected liabilities associated with legal proceedings and ~~out of court proceedings~~other matters arising from contractual claims, ~~contract renegotiations,~~ including ~~arbitration,~~arbitrations, fines and penalties due to antitrust proceedings and administrative matters. These provisions ~~represented~~represent the Company’s best estimate of the expected and probable liabilities associated with ~~pending~~ongoing litigation and ~~commercial proceedings and primarily~~ related to ~~the Gas & Power segment for €546 million and~~ the Exploration & Production segment for ~~€261~~€723 million. Additions and utilizations of €177 million and €1,099 million, respectively, mainly related to the Gas & Power segment and were recognized to take account of gas price revisions at long-term supply and sale contracts, including the settlement of certain arbitrations. Other changes of €175 million related to the reclassification to provisions for litigation of the expected liability incurred in connection with a dispute between EniPower and an Italian authority for the national grid on the use of certain allowances for the fulfillment of the obligations concerning GHG emissions at certain Eni’s plant for the production of co-generative power.

Provisions for taxes ~~of €732 million included~~other than income taxes related to the estimated ~~charges~~losses that the Company expects to incur ~~for unsettled~~to settle uncertain tax matters and tax claims pending with tax authorities in ~~connection with~~relation to uncertainties in ~~the application of tax~~applying rules ~~at certain Italian and~~in force for foreign subsidiaries inof the Exploration & Production segment ~~(€704 million).~~for €169 million.

Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC ~~of €207 million~~ represented the estimated liabilities accrued on the basis for third ~~parties~~party claims. Against such liability was recorded ~~a receivable~~receivables of ~~€147~~€162 million recognized towards insurance companies for reinsurance contracts.

Provisions for ~~redundancy incentives of €176 million were recognized due to a restructuring program involving the Italian personnel related to past reporting periods.~~

Provisions for onerous contracts of €165 million related to the execution of contracts where the expected costs exceed the relevant benefits. In particular, the provision comprised the estimated expected losses on unutilized infrastructures for gas transportation and on a regasification project.

~~Provisions for~~ losses on investments ~~of €153 million were made with respect~~included provisions relating to ~~certain investees~~investments whose loss exceeds the equity and primarily related to Industria Siciliana Acido Fosforico — ISAF — SpA (in liquidation) for ~~which expected or incurred losses exceeded carrying amounts.~~€131 million.

Provisions for the OIL mutual insurance scheme ~~of €88 million~~ 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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TABLE OF CONTENTS

~~Provisions for disposal and restructuring~~The liability relating to Eni’s commitment to cover the healthcare costs of ~~€58 million essentially related to the Chemical business line (€32 million) and to Syndial SpA (€14 million).~~

~~31 Provisions for employee benefits~~

(€ million) December 31, 2015 December 31, 2016
TFR 281 298
Foreign defined benefit plans 533 276
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans 156 124
Other foreign long-term benefit plans 153 170
1,123 868

~~Provisions for benefits upon termination of employment primarily related to a provisions accrued by Italian companies for employee retirement,~~personnel is determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code. The benefit is paid upon retirement as a lump sum, the amount of which corresponds to the total of the provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in the law regime, from January 1, 2007, accruing benefits have been contributing to a pension fund or a treasury fund held by the Italian administration for post-retirement benefits (INPS). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, contributions of future TFR provisions to pension funds or the INPS treasury fund determines that these amounts will be treated in accordance to a defined contribution scheme. Amounts already accrued before January 1, 2007 continue to be accounted for as defined benefits to be assessed based on actuarial assumptions.

Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and the United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement.

Group companies provide healthcare benefits. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company for retired managers.

Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers, jubilee awards and a defined benefit plan for certain employees engaged in the retail gas activity. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses that will be granted to those managers who will achieve certain individual performance goals weighted with the likelihood that the Company delivers the planned profitability targets. The benefit has a three-year vesting period and incurs when the commitment arises towards Eni’s management, based on the achievement of corporate goals. The estimate is subject to adjustments in subsequent years based on the results achieved and the update of the result forecasted (above or below the target). This benefit is applied pro-rata temporis over the three-year period depending on the results of the performance parameters. Provisions for the long-term incentive scheme are assessed on the basis of the ~~estimated trends of a performance indicator as benchmarked against a group of international oil companies. Both of these~~contributions paid by the Company.

Other employee benefit plans related to deferred monetary incentive ~~schemes normally vest over a three-year period. Jubilee awards are benefits due following~~plans for €132 million, the ~~attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration. The a defined~~isopensione plans (a post retirement benefit plan applicable to a specific category of employees) of Eni gas e luce SpA for ~~certain employees engaged in the retail gas activity is a supplementary pension plan set up in the 70’s~~€107 million, jubilee awards for €25 million and ~~managed by the Italian national agency~~other long-term plans for welfare. This fund, previously considered a defined contribution plan, became a defined benefit plan due to certain regulatory changes. The Eni personnel engaged in the gas activity came from the merger of the former “Italgas Più”.€14 million.

~~F-65~~

~~TABLE OF CONTENTS~~

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

	December 31, 2015										December 31, 2016										2019												2018
(€ million)	TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Other long-term benefit plans		Total		TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Other long-term benefit plans		Total		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		376		1,282		174		191		2,023		281		1,240		156		153		1,830		275		925		148		1,348		309		1,657		284		997		135		1,416		194		1,610
Current cost				41		2		54		97				28		2		56		86				19		2		21		55		76				27		2		29		42		71
Interest cost		6		41		3		1		51		6		34		3		1		44		4		37		3		44		1		45		4		31		2		37		1		38
Remeasurements:		(26)		(20)		(1)		(17)		(64)		19		22		(17)		1		25		5		41		24		70		1		71		1		(25)		13		(11)		30		19
- actuarial (gains) losses due to changes in demographic assumptions				(5)						(5)		(2)		(2)		(1)		(2)		(7)
- actuarial (gains) losses due to changes in financial assumptions				4		2		(14)		(8)		11		30		(2)		2		41		7		50		3		60		1		61				(31)		1		(30)		29		(1)
- experience (gains) losses		(26)		(19)		(3)		(3)		(51)		10		(6)		(14)		1		(9)		(2)		(9)		21		10				10		1		6		12		19		1		20
Past service cost and (gains) losses settlements				(9)		(1)		13		3				(7)		2		(3)		(8)				1		8		9		(2)		7				2		1		3		115		118
Plan contributions:				1						1				1						1				1				1				1				1				1				1
- employee contributions		��		1						1				1						1				1				1				1				1				1				1
Benefits paid		(25)		(56)		(7)		(53)		(141)		(8)		(33)		(6)		(31)		(78)		(15)		(28)		(9)		(52)		(88)		(140)		(15)		(35)		(9)		(59)		(74)		(133)
Reclassification to discontinued operations and asset held for sale		(52)		(181)		(23)		(41)		(297)
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		2		141		9		5		157				(390)		(16)		(7)		(413)				48		1		49		2		51		1		25		4		30		3		33
Present value of benefit liabilities at end of year (a)		281		1,240		156		153		1,830		298		895		124		170		1,487		269		1,044		177		1,490		278		1,768		275		925		148		1,348		309		1,657
Plan assets at beginning of year				710						710				707						707				545				545				545				588				588				588
Interest income				24						24				20						20				20				20				20				17				17				17
Return on plan assets				(11)						(11)				42						42				23				23				23				(21)				(21)				(21)
Past service cost and (gains) losses settlements														(3)						(3)
Administration expenses paid				(1)						(1)
Plan contributions:				42						42				25						25				14				14				14				25				25				25
- employee contributions				1						1				1						1				1				1				1				1				1				1
- employer contributions				41						41				24						24				13				13				13				24				24				24
Benefits paid				(24)						(24)				(19)						(19)				(19)				(19)				(19)				(26)				(26)				(26)
Reclassification to discontinued operations and asset held for sale				(86)						(86)
Changes in the scope of consolidation																																				(64)				(64)				(64)
Currency translation differences and other changes				53						53				(153)						(153)				49				49				49				26				26				26
Plan assets at end of year (b)				707						707				619						619				632				632				632				545				545				545
Net liability recognized at end of year (a-b)		281		533		156		153		1,123		298		276		124		170		868

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

~~Foreign defined benefit plans amounting to €276 million (€533 million at December 31, 2015) primarily related to pension plans for €184 million (€402 million at December 31, 2015).~~

~~Foreign employee~~Employee benefit plans included the liability attributable to ~~joint venture~~ partners operating in exploration and production activities of ~~€60~~€175 million (€~~281~~181 million at December 31, ~~2015)~~2018). Eni recorded a receivable for an amount equivalent to such liability.

Other employee benefit plans of €170 million (€153 million at December 31, 2015) related to: (i) defined benefit plans for €12 million (€11 million at December 31, 2015) related to the Gas fund; and (ii) long-term benefit plans for €158 million (€142 million at December 31, 2015) of which deferred monetary incentive plans for €99 million (€87 million at December 31, 2015), jubilee awards for €28 million (€27 million at December 31, 2015), long-term incentive plan for €14 million (€6 million at December 31, 2015) and other foreign long-term plans for €17 million (€22 million at December 31, 2015).

~~F-66~~F-67

TABLE OF CONTENTS

Costs charged to the profit and loss account consisted of the following:

(€ million)	TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Other long-term benefit plans		Total		Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Defined benefit plans		Other benefit plans		Total
2015
Current cost				41		2		54		97
Past service cost and (gains) losses on settlements				(9)		(1)		13		3
Interest cost (income), net:
- interest cost on liabilities		6		41		3		1		51
- interest income on plan assets				(24)						(24)
Total interest cost (income), net		6		17		3		1		27
- of which recognized in “Payroll and related cost”								1		1
- of which recognized in “Financial income (expense)”		6		17		3				26
Remeasurements for long-term plans								(17)		(17)
Other costs/Administration expenses paid				1						1
Total		6		50		4		51		111
- of which recognized in “Payroll and related cost”				33		1		51		85
- of which recognized in “Financial income (expense)”		6		17		3				26
2016
2019
Current cost				28		2		56		86				19		2		21		55		76
Past service cost and (gains) losses on settlements				(4)		2		(3)		(5)				1		8		9		(2)		7
Interest cost (income), net:
- interest cost on liabilities		6		34		3		1		44		4		37		3		44		1		45
- interest income on plan assets				(20)						(20)				(20)				(20)				(20)
Total interest cost (income), net		6		14		3		1		24		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)”		6		14		3				23		4		17		3		24				24
Remeasurements for long-term plans								(1)		(1)										1		1
Total		6		38		7		53		104		4		37		13		54		55		109
- of which recognized in “Payroll and related cost”				24		4		53		81				20		10		30		55		85
- of which recognized in “Financial income (expense)”		6		14		3				23		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:

	2015								2016										2019								2018
(€ million)	TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Total		TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Other benefit plans		Total		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				(5)				(5)		(2)		(2)		(1)		1		(4)
Actuarial (gains)/losses due to changes in financial assumptions				4		2		6		11		30		(2)		1		40		7		50		3		60				(31)		1		(30)
Experience (gains) losses		(26)		(19)		(3)		(48)		10		(6)		(14)				(10)		(2)		(9)		21		10		1		6		12		19
Return on plan assets				11				11				(42)						(42)				(23)				(23)				21				21
Change in asset ceiling																						(5)				(5)				5				5
		(26)		(9)		(1)		(36)		19		(20)		(17)		2		(16)		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

~~F-67~~F-68

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, 2015
Plan assets with a quoted market price 41 96 254 10 2 2 23 273 701
Plan assets without a quoted market price 6 6
41 96 254 10 2 2 29 273 707
December 31, 2016
Plan assets with a quoted market price 105 49 270 11 1 65 14 101 616
Plan assets without a quoted market price 3 3
105 49 270 11 1 65 17 101 619

Plan assets are generally managed by external asset managers pursuing investment strategies, defined by Eni’s companies, with the aim of ensuring that assets are sufficient to pay the benefits. For this purpose, the investments are aimed at maximizing the expected return and limit the risk level through proper diversification.

The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for ~~2016~~2020 consisted of the following:

		TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other long-term benefit plans			Italian defined benefit plans		Foreign defined benefit plans		FISDE, foreign medical plans and other		Other benefit plans
2015
2019
Discount rate	(%)		2.0		0.8-15.3		2.0		0.5-2.0	(%)		0.7		0.0-13.7		0.7		0.0-0.7
Rate of compensation increase	(%)		3.0		2.0-13.3					(%)		1.7		1.3-12.5
Rate of price inflation	(%)		2.0		0.6-9.7		2.0		2.0	(%)		0.7		0.8-11.3		0.7		0.7
Life expectations on retirement at age 65	(years)				13-24		24			(years)				13-25		24
2016
2018
Discount rate	(%)		1.0		0.6-17.5		1.0		0.0-1.0	(%)		1.5		0.8-18.0		1.5		0.2-1.5
Rate of compensation increase	(%)		2.0		1.0-15.0					(%)		2.5		1.5-16.5
Rate of price inflation	(%)		1.0		0.6-13.5		1.0		1.0	(%)		1.5		0.8-16.0		1.5		1.5
Life expectations on retirement at age 65	(years)				13-24		24			(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

~~2015~~2019

Discount rate

(%)

~~2.0~~0.8-1.0

~~0.8-3.8~~0.0-2.0

~~3.5-15.3~~2.6-13.7

~~9.4-9.5~~7.3-11.3

~~0.8-15.3~~0.0-13.7

Rate of compensation increase

(%)

~~2.0-3.0~~1.3-3.0

~~2.5-4.7~~2.5-3.6

~~5.0-13.3~~2.0-12.5

~~10.0~~10.0-11.3

~~2.0-13.3~~1.3-12.5

Rate of price inflation

(%)

~~2.0~~1.3-2.0

~~0.6-3.0~~0.8-3.1

~~3.5-9.7~~2.6-11.3

~~5.5-8.2~~3.3-5.0

~~0.6-9.7~~0.8-11.3

Life expectations on retirement at age 65

(years)

21-22

~~22-24~~24-25

~~13-15~~13-17

~~13-24~~13-25

~~2016~~2018

Discount rate

(%)

~~1.0-2.0~~1.5-1.9

~~0.6-2.7~~0.8-2.9

~~3.5-17.5~~3.7-18.0

~~7.3-8.1~~8.0-13.3

~~0.6-17.5~~0.8-18.0

Rate of compensation increase

(%)

~~1.0-3.0~~1.5-3.0

~~2.3-3.8~~2.5-3.8

~~5.0-15.0~~5.0-16.5

~~7.8-10.0~~10.0-13.3

~~1.0-15.0~~1.5-16.5

Rate of price inflation

(%)

~~1.0-1.8~~1.5-2.0

~~0.6-3.4~~0.8-3.3

~~3.5-13.5~~3.7-16.0

~~5.0-5.5~~3.5-5.0

~~0.6-13.5~~0.8-16.0

Life expectations on retirement at age 65

(years)

21-22

~~23-24~~23-25

~~13-15~~13-17

~~13-24~~13-25

The discount rate used was determined on the base of corporate bond yields (rating AA) in countries with a significant market, or in the absence, of government bond yields. The demographic tables adopted are those used by each country for the assessments of IAS 19. The inflation rate is consistent with the discount rate adopted determined based on the inflation rate implicit in the securities financial markets.

~~F-68~~

~~TABLE OF CONTENTS~~

The effects of a possible change in the main actuarial assumptions at the end of the year are listed below:

Discount rate Rate
of price
inflation Rate of
increases in
pensionable
salaries Healthcare
cost
trend rate Rate of
increases to
pensions in
payment
(€ million) 0.5% Increase 0.5% Decrease 0.5% Increase 0.5% Increase 0.5% Increase 0.5% Increase
December 31, 2015
Effect on DBO
TFR (17) 18 12
Foreign defined benefit plans (75) 84 46 26 54
FISDE and other foreign medical plans (8) 9 9
Other long-term benefit
plans (2) 2 1
December 31, 2016
Effect on DBO
TFR (15) 16 10
Foreign defined benefit plans (57) 66 33 15 23
FISDE and other foreign medical plans (7) 8 8
Other long-term benefit
plans (2) 2 1

	Discount rate				Rate of price inflation		Rate of increases in pensionable salaries		Healthcare cost trend rate		Rate of increases to pensions in payment
(€ million)	0.5% Increase		0.5% Decrease		0.5% Increase		0.5% Increase		0.5% Increase		0.5% Increase
December 31, 2019
Italian defined benefit plans		(12)		13		8
Foreign defined benefit plans		(67)		77		31		18				34
FISDE, foreign medical plans and other		(9)		10						10
Other benefit plans		(4)		1		1
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 ~~€87~~€130 million, of which ~~€52~~€57 million related to defined benefit plans.

The following is an analysis by maturity date of the liabilities for employee benefit ~~plans:~~

(€ million) TFR Foreign
defined
benefit plans FISDE and
other foreign
medical plans Other
long-term
benefits
December 31, 2015
2016 4 31 5 31
2017 5 33 5 37
2018 6 43 5 57
2019 8 34 5 2
2020 10 37 6 2
2021 and thereafter 248 355 130 47
December 31, 2016
2017 13 31 5 37
2018 14 44 5 59
2019 15 33 5 52
2020 17 33 5 3
2021 19 38 5 3
2022 and thereafter 220 97 99 42

~~The~~plans and their relative weighted average ~~duration of the~~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 ~~for employee benefit plans was the following:~~

TFR Foreign
defined
benefit plans FISDE and
other foreign
medical plans Other
long-term
benefits
2015
Weighted average duration (years) 12.0 16.5 14.1 4.3
2016
Weighted average duration (years) 10.3 17.9 13.9 3.4

(€ 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

~~F-69~~F-70

TABLE OF CONTENTS

~~32 Deferred tax liabilities~~

~~Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for €4,286 million (€3,355 million at December 31, 2015).~~

(€ million) Amount at
December 31,
2015 Additions Deductions Currency
translation
differences Other
changes Amount at
December 31,
2016
7,425 1,796 (1,486) 229 (1,297) 6,667

~~Deferred tax assets and liabilities consisted of the following:~~

(€ million) December 31, 2015 December 31, 2016
Deferred tax liabilities 10,780 10,953
Deferred tax assets available for offset (3,355) (4,286)
7,425 6,667
Deferred tax assets not available for offset (3,853) (3,790)
Net deferred tax liabilities 3,572 2,877

Net deferred tax liabilities of €2,877 million (€3,572 million at December 31, 2015) included the recognition of the deferred tax effect against equity of: (i) the fair value measurement of derivatives designated as cash flow hedge (deferred tax liabilities for €57 million); (ii) the revaluation of defined benefit plans (deferred tax liabilities for €13 million); and (iii) the fair value measurement of available-for-sale securities (deferred tax liabilities for €1 million).

The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below:

(€ million)	Carrying amount at December 31, 2015		Additions		Deductions		Currency translation differences		Other changes		Carrying amount at December 31, 2016		Carrying amount at December 31, 2019		Carrying amount at December 31, 2018
Deferred tax liabilities
Accelerated tax depreciation		8,424		1,527		(583)		168		(637)		8,899		6,796		6,612
Leasing														1,375
Difference between the fair value and the carrying amount of assets acquired		1,150		114		(207)		42		170		1,269		617		849
Site restoration and abandonment (tangible assets)		644				(171)		20		(145)		348		126		85
Application of the weighted average cost method in evaluation of inventories		46		41		(7)		1				81		97		44
Capitalized interest expense		77				(9)		1		(53)		16
Other		439		114		(509)		(3)		299		340		572		366
		10,780		1,796		(1,486)		229		(366)		10,953		9,583		7,956
Deferred tax assets, gross
Carry-forward tax losses		(3,598)		(1,377)		95		(88)		246		(4,722)		(6,065)		(5,528)
Site restoration and abandonment (provisions for contingencies)		(2,415)		(768)		186		5		111		(2,881)		(2,242)		(1,986)
Timing differences on depreciation and amortization		(2,195)		(253)		140		(63)		111		(2,260)		(2,022)		(2,104)
Accruals for impairment losses and provisions for contingencies		(1,380)		(370)		337						(1,413)		(1,513)		(1,460)
Leasing														(1,385)
Impairment losses		(902)		(121)		224		(2)		(105)		(906)		(946)		(792)
Over/Under lifting														(525)		(604)
Employee benefits		(171)		(33)		16				25		(163)		(209)		(212)
Unrealized intercompany profits		(257)				3		2		134		(118)		(120)		(124)
Other		(1,389)		(72)		207		(39)		58		(1,235)		(740)		(546)
		(12,307)		(2,994)		1,208		(185)		580		(13,698)		(15,767)		(13,356)
Impairments of deferred tax assets		5,099		667		(254)		80		30		5,622
Accumulated write-downs of deferred tax assets														6,744		5,741
Deferred tax assets, net		(7,208)		(2,327)		954		(105)		610		(8,076)		(9,023)		(7,615)
Net deferred tax liabilities		3,572		(531)		(532)		124		244		2,877

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.

Carry-forward tax losses amounted to €21,360 million out of which €15,256 million can be carried forward indefinitely. Carry-forward tax losses were €12,039 million and €9,321 million at Italian

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subsidiaries and foreign subsidiaries, respectively. Deferred tax assets recognized on these losses amounted to €2,936 million and €3,129 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. ~~An average~~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. The corresponding average rate for foreign subsidiaries was ~~36%~~33.6%.

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Carry-forward tax losses amounted to €16,478 million and can be used indefinitely for €13,083 million. Carry-forward tax losses regarded Italian companies for €9,889 million and foreign companies for €6,589 million. Deferred tax assets recognized on these losses amounted to €2,330 million and €2,392 million, respectively.

~~Provisions for impairments~~Accumulated write-downs of deferred tax assets ~~of €5,622 million~~ related to Italian companies for ~~€4,020~~€5,329 million and ~~foreign~~non-Italian companies for ~~€1,602~~€1,415 million.

~~33 Other non-current liabilities~~

(€ million) December 31, 2015 December 31, 2016
Fair value of derivatives financial instruments 98 161
Current income tax liabilities 23 35
Other payables towards tax authorities 29 9
Cautionary deposits 267 265
Other payables 81 51
Other liabilities 1,354 1,247
1,852 1,768

~~Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.~~

Cautionary deposits of €265 million (€267 million at December 31, 2015) related for €224 million (€232 million at December 31 2015) to deposits from retail customers for the supply of gas and electricity.

Other liabilities of €1,247 million (€1,354 million at December 31, 2015) included advances received from Suez following a long-term agreement for supplying natural gas and electricity of €664 million (€736 million at December 31, 2015). The current portion isTaxes are also described in note 2832 — ~~Other current liabilities.~~Income taxes.

~~Liabilities with related parties are described in note 47 — Transactions with related parties.~~

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3423 Derivative financial instruments and hedge accounting

	December 31, 2015						December 31, 2016						December 31, 2019						December 31, 2018
(€ 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		223		311		2		188		268		2		97		43		2		99		46		2
- Interest currency swap		97		33		2		38		83		2		26				2		14		71		2
- Outright		7		2		2		17		15		2		8		5		2		3		5		2
		327		346				243		366				131		48				116		122
Derivatives on interest rate
- Interest rate swap		30		20		2		10		12		2		13		34		2		18		6		2
		30		20				10		12				13		34				18		6
Derivatives on commodities
- Future		1,586		1,483		1		624		611		2		192		181		1		1,060		1,107		1
- Over the counter		550		491		2		133		120		1		89		58		2		306		284		2
- Options										1		2
- Other								4		5		2		12				2		1		5		2
		2,136		1,974				761		737				293		239				1,367		1,396
		2,493		2,340				1,014		1,115				437		321				1,501		1,524
Trading derivatives
Derivatives on commodities
- Over the counter		2,647		3,054		2		1,495		1,490		2		2,387		1,953		2		992		1,031		2
- Future		409		559		1		561		574		1		348		313		1		367		263		1
- Options		153		176		2		211		157		2		21		22		2		80		71		2
		3,209		3,789				2,267		2,221				2,756		2,288				1,439		1,365
Cash flow hedge derivatives
Derivatives on commodities
- Over the counter		19		614		2		309		150		2		1		596		2		311		196		2
- Future		107				1		1		18		1		34		148		1
- Options																2		2		26		15		1
		126		614				310		168				35		746				337		211
Embedded derivatives		20				2
Option embedded in convertible bonds				26		2		46		46		2		11		11		2		21		21		2
Gross amount		5,848		6,769				3,637		3,550				3,239		3,366				3,298		3,121
Offsetting		(2,410)		(2,410)				(1,281)		(1,281)				(612)		(612)				(1,636)		(1,636)
Net amount		3,438		4,359				2,356		2,269				2,627		2,754				1,662		1,485
Of which:
- current		3,220		4,261				2,248		2,108				2,573		2,704				1,594		1,445
- non-current		218		98				108		161				54		50				68		40

Derivative fair values were estimated 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 derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not relate to specific trade or financing transactions.IFRS.

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Fair values of trading derivatives consisted of derivatives entered for trading purposes and proprietary trading.

Fair value of cash flow hedge derivatives related to ~~the~~commodity hedges were entered into by the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation ~~mechanism~~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 3625 — Shareholders’ equity and in note 4029 — ~~Operating expenses.~~Costs. Information on hedged risks and hedging policies is disclosed in note 3827 — Guarantees, commitments and risks — Risk factors.

Options embedded in convertible bonds ~~of €46 million as of December 31, 2016, related~~relate to equity-linked cash ~~settled bonds. Options embedded in convertible bonds of €26 million as of December 31, 2015, related to the convertible bond into ordinary shares of Snam SpA expired on January 18, 2016.~~settled. More information is disclosed in note 2918 — ~~Long-term debt and current portion~~Finance debts.

The offsetting of ~~long-term debt.~~financial derivatives related to the Gas & Power segment.

During ~~the 2016,~~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.

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~~35 Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale~~

~~Discontinued operations~~

~~Saipem~~

~~On January 22, 2016, following the fulfillment of all the conditions precedent, among which the consensus~~The breakdown of the ~~Antitrust Authority,~~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 ~~closed~~enters into commodities derivatives traded on organized markets (like MTF and OTF) and commodities derivatives traded over the ~~sale transaction of 12.503%~~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 ~~share capital of Saipem SpA to CDP Equity SpA. The transaction referred to 55,176,364 Saipem shares at~~underlying commodity but are designated as hedging instruments in a price of €8.3956 per share for a total consideration of €463 million. At the same date, a shareholder agreement between Eni and CDP Equity entered into force and established the joint control of the two shareholders over Saipem. Therefore, following the loss of control, Saipem was derecognized from Eni’s consolidated accounts and accounted for using the equity method. At the date of the loss of the control (January 22, 2016), the retained interest of 30.42% in the former subsidiary was aligned to the market price of €4.2 per share corresponding to a carrying amount of €564 million with a charge through profit and loss of €441 million (with respect to the carrying amount at the opening balance).

~~Versalis~~

~~In 2016, Eni’s chemical segment ceased to be classified as a disposal group in accordance to IFRS 5 due to termination of the negations with US-based SK Capital~~cash flow hedge fund, that had shown an interest in acquiring a 70% stake in Eni subsidiary Versalis SpA, the parent company of the chemical business. Therefore, Eni’s consolidated accounts as of and for the year 2016 have been prepared accounting this business as part of the continuing operations. Based on IFRS 5 provisions, in case of cessation of classification as held for sale, management is required to amend financial statements retrospectively to the date of initial classification as held for sale, December 31, 2015, as though the disposal group never qualified as held for sale. Accordingly, the opening balance of the consolidated accounts 2016 were amended to reinstate the criteria of the continuing use to evaluate Versalis by aligning its book value to the recoverable amount, given by the higher of fair value less cost to sell and value-in-use. Under IFRS 5, Versalis was measured at the lower of its carrying amount and fair value less cost to sell. Management estimated the value-in-use of the fixed assets of Versalis’ business units by identifying a single Cash Generating Unit consistently with Eni’s industrial plan for the four-year period 2016-2019 used at December 31, 2015 that considered Versalis as an integrated unit with a view to disposing or monetizing it as a whole. The value-in-use was estimated by discounting the future expected cash flows of the industrial plan of a standalone Versalis, which factored in the earnings volatility of a pool of chemical peers of Versalis, thus determining a beta parameter independent from Eni in the same manner as the Gas & Power segment. Further information is provided in note 16 — Property, plant and equipment. This amendment in Versalis evaluation marginally affected the opening balance of Eni’s consolidated net assets (an increase of €294 million) and was neutral to the Group’s net borrowings.relation.

~~The main economic and financial data of the discontinued operations net of intragroup transactions are provided below.~~

~~Saipem~~

(€ million) 2014 2015 2016
Revenues 11,644 10,277
Operating expenses 12,731 12,199
Operating profit (1,087) (1,922)
Finance income (expense) 116 60
Income (expense) from investments 24 30 (413)
Profit before income taxes (947) (1,832) (413)
Income taxes (2) (142)
Net profit (949) (1,974) (413)
- attributable to Eni (417) (826) (413)
- attributable to non-controlling interest (532) (1,148)
Earnings per share (€ per share) (0.12) (0.23) (0.12)
Net cash provided by operating activities 273 (1,226)
Net cash flow from investing activities (684) (456)
Net cash used in financing activities 126 (57)
Capital expenditures 694 561

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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.

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
Net income (loss) on cash flow hedging derivatives		(2)				12
Net income (loss) on other derivatives		289		129		(44)
		287		129		(32)

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 ~~for 2016 included: (i) a loss from measurement at~~in the Gas & Power segment.

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 ~~retained interest~~following:

(€ million)	2019		2018		2017
Derivatives on exchange rate		9		(329)		809
Derivatives on interest rate		(23)		22		28
		(14)		(307)		837

Net financial income from derivative financial instruments was recognized in ~~Saipem at~~connection with the ~~date of the loss of control (22 January 2016) for €441 million; (ii) a net gain from utilization of the reserve for exchange differences and of the reserve for the valuation at~~ fair value valuation of ~~cash flow~~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 ~~for €28 million.~~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.

Finance income (expense) with related parties 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

~~Assets~~As of December 31, 2019, assets held for sale ~~amounted to €14 million and~~ related to sales of tangible assets ~~and investments.~~for €18 million.

In ~~2016,~~the course of 2019, Eni ~~sold to MOL Group,~~finalized the sale of Agip Oil Ecuador BV, which retains a ~~Hungarian~~service contract for the development of Villano oil~~&gas company,~~ field, and of a 100% stake of the subsidiaries Eni Slovenija doo and Eni Hungaria Zrt, two companies operating in the retail and wholesale marketing of fuels with activities in Slovenia and Hungary for a total consideration of €69 million.minority investment.

~~More information is provided in note 37 — Other information — Supplemental cash flow information and note 42 — Income (expense) from investments.~~

3625 Shareholders’ equity

~~Non-controlling interest~~

Net profit Shareholders’ equity
(€ million) 2015 2016 December 31,
2015 December 31,
2016
Saipem SpA (600) 1,872
Others 5 7 44 49
(595) 7 1,916 49

Eni shareholders’ equity

(€ million)		December 31, 2015		December 31, 2016		December 31, 2019		December 31, 2018
Share capital			4,005		4,005		4,005		4,005
Retained earnings							37,436		36,702
Cumulative currency translation differences							7,209		6,605
Legal reserve			959		959		959		959
Reserve for treasury shares			581		581		981		581
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect			(474)		189		(465)		(9)
Reserve related to the fair value of available-for-sale securities net of the tax effect			8		4
Reserve related to the defined benefit plans net of tax effect			(101)		(112)		(173)		(130)
Other comprehensive income on equity-accounted investments							60		66
Other comprehensive income on other investments							12		15
Other reserves			180		211		190		190
Cumulative currency translation differences			9,129		10,319
Treasury shares			(581)		(581)		(981)		(581)
Retained earnings			51,985		40,367
Interim dividend			(1,440)		(1,441)		(1,542)		(1,513)
Net loss for the year			(8,778)		(1,464)
Other items of comprehensive income related to discontinued operations			20
Net profit (loss) for the year							148		4,126
	��		55,493		53,037		47,839		51,016

Share capital

As of December 31, ~~2016,~~2019, the parent company’s issued share capital consisted of €4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (same amounts as of December 31, ~~2015)~~2018).

On May ~~12, 2016,~~14, 2019, Eni’s Shareholders’ Meeting ~~declared~~resolved: (i) to distribute a dividend of ~~€0.40~~€0.41 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the ~~2015~~2018 dividend of ~~€0.80~~€0.83 per share, of which ~~€0.40~~€0.42 per share was already paid as interim ~~dividend.~~dividend in September 2018. The ~~balance~~final amount was paid on 22 May ~~25, 2016,~~2019, to shareholders on the register on May ~~23, 2016,~~20, 2019, record date on May ~~24, 2016.~~21, 2019; (ii) to authorise the Board of Directors — pursuant to and for the purposes of Article 2357 of the Italian Civil Code — to proceed, within a period of eighteen months from the date of the resolution, with the purchase of a maximum number 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.

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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 ~~of €581 million (same amount as of December 31, 2015)~~ represents the reserve that was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings.

~~Reserves related to the fair value measurement of cash flow hedging derivatives,~~

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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		Other comprehensive income on equity-accounted investments		Investments valued at fair value
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

*
~~available-for-sale financial assets and~~

OCI for defined benefit plans

The reserves related to the valuation at fair value of cash flow hedging derivatives, available-for-sale financial instruments and defined benefit plans, net of the related tax effect, consisted of the following:

Cash flow hedge derivatives Available-for-sale
financial instruments Defined benefit plans Total
(€ million) Gross
reserve Deferred
tax
liabilities Net
reserve Gross
reserve Deferred
tax
liabilities Net
reserve Gross
reserve Deferred
tax
liabilities Net
reserve Gross
reserve Deferred
tax
liabilities Net
reserve
Reserve as of December 31, 2014 (384) 100 (284) 13 (2) 11 (154) 32 (122) (525) 130 (395)
Changes of the year 2015 (439) 108
(331)
(4) 1
(3)
34 (20) 14 (409) 89
(320)

Reclassification to discontinued operations 5 (1) 4 10 (2) 8 15 (3) 12
Foreign currency translation differences (1)
(1)
(1)
(1)

Reversal of the year 2015 181 (44) 137 181 (44) 137
Reserve as of December 31, 2015 (637) 163 (474) 9 (1) 8 (111) 10 (101) (739) 172 (567)
Changes of the year 2016 360 (90) 270 (3)
(3)
16 (35)
(19)
373 (125) 248
Foreign currency translation differences (4) 12 8 (4) 12 8
Reversal of the year 2016 523 (130) 393 (1)
(1)
522 (130) 392
Reserve as of December 31, 2016 246 (57) 189 5 (1) 4 (99) (13) (112) 152 (71) 81

~~Reserve for available-for-sale financial instruments net of tax effect of €4 million (€8 million~~ at December 31, ~~2015) related~~2019 includes €7 million relating to ~~the fair value valuation of securities.~~equity-accounted investments.

Other reserves

Other reserves ~~amounting to €211 million (€180 million at December 31, 2015)~~ related to:

•

(i) a reserve of ~~€247~~€127 million representing the increase in Eni shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its ~~subsidiary Snamprogetti SpA to Saipem Projects SpA (both merged into Saipem SpA) at a price higher than the book value of the interest transferred (same amount as of December 31, 2015);~~

•

subsidiaries; (ii) a reserve of €63 million deriving from Eni SpA’s ~~equity (same amount as of December 31, 2015);~~

•

~~a reserve of €21 million relating to the share of “Other comprehensive income” on equity accounted entities (a negative reserve of €11 million at December 31, 2015);~~

•

a reserve of €4 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 48.55% in the subsidiary Tigáz Zrt (€5 million for the acquisition of 47.60% at December 31, 2015);

•

a negative reserve of €124 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 45.99% in the subsidiary Altergaz SA, now Eni Gas & Power France SA (same amount as of December 31, 2015).

equity.

Cumulative foreign currency translation differences

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 ~~33,045,197~~61,635,679 of Eni’s ordinary shares ~~(same amount as of~~(33,045,197 at December 31, ~~2015)~~2018) were held in treasury for a total cost of ~~€581~~€981 million ~~(same amount as of~~(€581 million at December 31, ~~2015)~~2018). On April 13, 2017, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017-2019 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.

Interim dividend

The interim dividend for the year ~~2016~~2019 amounted to ~~€1,441~~€1,542 million corresponding to ~~€0.40~~€0.43 per share, as resolved by the Board of Directors on 19 September ~~15, 2016,~~2019, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on 25 September ~~21, 2016, record date on September 19, 2016.~~2019.

Distributable reserves

As of December 31, ~~2016,~~2019, Eni shareholders’ equity included distributable reserves of approximately ~~€48.2~~€43 billion.

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Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA
to consolidated net profit and shareholders’ equity

Net profit Shareholders’ equity
(€ million) 2015 2016 December 31,
2015 December 31,
2016
As recorded in Eni SpA’s Financial Statements 2,183 4,521 39,562 41,935
Excess of net equity stated in the separate accounts of consolidated
subsidiaries over the corresponding carrying amounts of the parent company (10,778) (5,480) 18,508 12,384
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity (58) (44) 308 240
- adjustments to comply with Group account policies (523) (188) 1,137 461
- elimination of unrealized intercompany profits 96 (56) (1,219) (801)
- deferred taxation (270) (210) (880) (1,133)
- other adjustments (23) (7)
(9,373) (1,457) 57,409 53,086
Non-controlling interest 595 (7) (1,916) (49)
As recorded in Consolidated Financial Statements (8,778) (1,464) 55,493 53,037

	Net profit				Shareholders’ equity
(€ million)	2019		2018		December 31, 2019		December 31, 2018
As recorded in Eni SpA’s Financial Statements		2,978		3,173		41,636		42,615
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
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(6)				202		153
- adjustments to comply with Group accounting policies		(348)		862		1,424		2,000
- elimination of unrealized intercompany profits		(74)		177		(593)		(519)
- deferred taxation		405		59		20		(359)
		155		4,137		47,900		51,073
Non-controlling interest		(7)		(11)		(61)		(57)
As recorded in Consolidated Financial Statements		148		4,126		47,839		51,016

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3726 Other information

Supplemental cash flow information

(€ million) 2014 2015 2016
Investment in consolidated subsidiaries and businesses
Current assets 96
Non-current assets 265
Net borrowings (19)
Current and non-current liabilities (291)
Net effect of investments 51
Fair value of investments held before the acquisition of control (15)
Purchase price 36
less:
Cash and cash equivalents
Investment in consolidated subsidiaries and businesses net of cash
and cash equivalent 36
Disposal of consolidated subsidiaries and businesses
Current assets 5 44 6,526
Non-current assets 2 125 8,615
Net borrowings (77) (5,415)
Current and non-current liabilities (2) (45) (6,334)
Net effect of disposals 5 47 3,392
Reclassification of foreign currency translation differences among other items of comprehensive income (34) 7
Fair value of share capital held after the sale of control (1,006)
Gain (loss) on disposal (5) 66 11
Non-controlling interest (1,872)
Selling price 79 532
less:
Cash and cash equivalents (6) (894)
Disposal of consolidated subsidiaries and businesses net of cash and cash equivalent 73 (362)

Cash flow from disposals of 2016 related to: (i) the consideration of €463 million received from the sale of 12.503% of Saipem to CDP Equity SpA, which was reported net of Saipem’s cash and cash equivalents disposed of for €889 million (as established by IAS 7). Due to the presentation of the Saipem Group as discontinued operations in 2015 Financial Statements, such cash and cash equivalents were included as reconciliation item in 2016 and 2015 Cash Flow Statement, in order to present the Group cash and cash equivalents net of those related to discontinued operations; (ii) the sale of a 100% stake in Eni Slovenija doo and Eni Hungaria Zrt for a total consideration of €69 million and cash and cash equivalents divested of €5 million.

~~38 Guarantees, commitments and risks~~

~~Guarantees~~

December 31, 2015 December 31, 2016
(€ million) Unsecured
guarantees Other
guarantees Total Unsecured
guarantees Other
guarantees Total
Eni
Consolidated subsidiaries 7,929 7,929 5,869 5,869
Unconsolidated subsidiaries 113 113 246 246
Consolidated joint operations 6 6
Joint ventures and associates 6,122 75 6,197 6,124 2,112 8,236
Others 7 216 223 202 202
6,129 8,339 14,468 6,124 8,429 14,553
Engineering & Construction
Consolidated subsidiaries 3,349 3,349
Joint ventures and associates 150 68 218
150 3,417 3,567
6,279 11,756 18,035 6,124 8,429 14,553

(€ million)	2019		2018		2017
Investment in consolidated subsidiaries and businesses
Current assets		1		44
Non-current assets		12		198
Net borrowings				11
Current and non-current liabilities		(6)		(47)
Net effect of investments		7		206
Fair value of investments held before the acquisition of control				(50)
Non-controlling interests		(2)
Gain on a bargain purchase				(8)
Purchase price		5		148
less:
Cash and cash equivalents				(29)
Consolidated subsidiaries and businesses net of cash and cash equivalent acquired		5		119
Disposal of consolidated subsidiaries and businesses
Current assets		77		328		166
Non-current assets		188		5,079		814
Net borrowings		11		785		(252)
Current and non-current liabilities		(57)		(3,470)		(205)
Net effect of disposals		219		2,722		523
Reclassification of foreign currency translation differences among other items of comprehensive income		(24)		113
Fair value of share capital held after the sale of control				(3,498)
Fair value valuation for business combination				889
Gain (loss) on disposal		16		13		2,148
Selling price		211		239		2,671
less:
Cash and cash equivalents		(24)		(286)		(9)
Consolidated subsidiaries and businesses net of cash and cash equivalent disposed of		187		(47)		2,662

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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 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.

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
Consolidated subsidiaries		4,323		5,082
Unconsolidated subsidiaries		197		196
Joint ventures and associates		4,075		4,056
Others		267		163
		8,862		9,497

Guarantees include the guarantees issued by Eni SpA on behalf of third-party contractors and lenders who have a certain contractual obligations to build and finance the construction of an LNG Floating Production unit for the development of the Coral gas reserves discovered in Area 4 offshore Mozambique. The total value of 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 LNG 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 and

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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 funds 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 EPCC that regulates the petroleum activities in Area 4, 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, 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 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 ~~€5,869~~€4,323 million (€~~7,929~~5,082 million at December 31, ~~2015)~~2018) primarily consisted ~~of: (i)~~of guarantees given to third parties relating to bid bonds and performance bonds for ~~€1,965~~€2,886 million (€~~4,381~~2,576 million at December 31, ~~2015)~~2018). The decrease of €2,416 million related to the reclassification to joint ventures and associates of the guarantees given on behalf of Saipem Group for €2,483 million as of December 31, 2015; (ii) VAT recoverable from tax authorities for €1,380 million (€1,310 million at December 31, 2015); (iii)In 2019 a bank guarantee of €1,010 million, issued on behalf of GasTerra ~~in order~~ to obtain the ~~renunciation~~waiver to a temporary seizure ~~order on~~of Eni’s investment in Eni International BV, ~~requested and obtained~~which was ordered by a Netherlands Court in July ~~2016;~~2016, was settled. In July 2019, the arbitration proceeding, initiated by the parties to settle the dispute, issued an award favourable to Eni and ~~(iv) insurance risk~~ruled the claim of GasTerra for ~~€141 million reinsured by Eni (€140 million at December 31, 2015).~~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, ~~2016,~~2019, the underlying commitment issued on behalf of consolidated subsidiaries covered by such guarantees was ~~€5,785~~€4,013 million (€~~7,808~~5,000 million at December 31, ~~2015)~~2018).

Other guarantees issued on behalf of unconsolidated subsidiaries of €246 million (€113 million at December 31, 2015) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for €240 million (€102 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €53 million (€113 million at December 31, 2015).

~~Unsecured guarantees and other guarantees~~Guarantees issued on behalf of joint ventures and associates of ~~€8,236~~€4,075 million (€~~6,197~~4,056 million at December 31, ~~2015)~~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 ~~€6,122~~€499 million ~~(same amount as of~~(€499 million at December 31, ~~2015)~~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 ~~relating to~~for the construction of the Milan-Bologna fast track railway by the CEPAV (Consorzio Eni per l’Alta Velocità) Uno (Saipem 50.36%); consortium members, excluding Saipem Group, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) guarantees given to third parties relating to bid bonds and performance bonds for €1,705 million given on behalf of Saipem Group; and (iii) unsecured guarantees and other guarantees given to banksUno; (iv) a guarantee issued in relation to loans and lines of credit received for €82 million (€12 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €2,109 million (€72 million at December 31, 2015).

~~Unsecured and other guarantees given on behalf of third parties of €202 million (€223 million at December 31, 2015) primarily consisted of guarantees issued on behalf~~favor of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc ~~(Eni 13.6%~~(Eni’s interest 13.60%) ~~as security against payment~~to cover contractual commitments of paying re-gasification fees ~~in connection with the regasification activity~~ for ~~€193~~€181 million (€~~187~~177 million at December 31, ~~2015)~~2018). At December 31, ~~2016,~~2019, the underlying commitment issued on behalf of joint ventures and associates covered by such guarantees was ~~€202~~€2,109 million (€~~214~~2,159 million at December 31, ~~2015)~~2018).

Commitments and risks

(€ million)	December 31, 2015		December 31, 2016		December 31, 2019		December 31, 2018
Commitments		21,241		20,682		74,338		54,611
Risks		422		605		676		673
		21,663		21,287		75,014		55,284

~~Other commitments of €20,682 million (€21,241 million at December 31, 2015)~~Commitments related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to ~~€12,415~~be €65,374 million (€~~12,794~~52,397 million at December 31, ~~2015); (ii) commitments entered~~2018). The increase of €12,977 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%) for 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 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 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 ~~Exploration~~joint venture Vår Energi AS intended to cover the decommissioning contractual obligations; (ii) two parent company guarantees for a total amount of €6,527 million given on behalf of Eni Abu Dhabi Refining & ~~Production segment for leasing contracts (chartering, operation~~Trading BV following the Share Purchase Agreement to acquire from ADNOC a 20% equity interest in ADNOC Refining and ~~maintenance)~~the set-up of ~~FPSO vessels~~ADNOC Global Trading Ltd dedicated to ~~be used for development projects~~marketing petroleum products. The first parent company guarantee of €2,965 million was issued to guarantee the obligations under the Share Purchase Agreement and will remain in ~~Angola~~place until the payment of the Deferred Consideration expected by March 31, 2020. The second parent company guarantee of €3,562 million has been issued to guarantee the obligations set out in the Shareholders Agreements and ~~Ghana. Total commitments amounted to approximately €4,344 million and have a duration ranging between 14 and 16 years (€4,364 million at December 31, 2015);~~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 ~~acquisition~~purchase of volumes of regasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031) ~~and towards Gulf LNG Energy for the acquisition of regasification capacity at the Pascagoula terminal (5.8 BCM/y) over a twenty-year period (until 2031)~~. The expected commitments ~~have been~~were estimated at ~~€2,541~~€1,978 million ~~and €1,156 million, respectively~~ (€~~2,590 million and €1,191~~2,079 million at December 31, ~~2015, respectively)~~2018) and have been included in off-balance sheet contractual commitments in the ~~following~~table “Future payments under contractual obligations” in the paragraph ~~“Liquidity risk”; and (iv) a memorandum of intent signed with~~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 an equitable compensation of €324 million to Eni’s counterparties. 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 the moment, the risk of losing the proceeding is considered unlikely; (iv) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest ~~€129~~€114 million (€~~133~~116 million at December 31, ~~2015)~~2018) 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.

Risks ~~of €605 million (€422 million at December 31, 2015) primarily concerned~~relate to potential risks associated ~~with~~with: (i) contractual assurances given to acquirers of certain investments and businesses of Eni for ~~€334~~€248 million (€~~326~~244 million at December 31, ~~2015) and the value of~~2018); (ii) assets of third parties under the custody of Eni for ~~€271~~€428 million (€96429 million at December 31, ~~2015)~~2018).

~~Non-quantifiable~~Other commitments and risks

A parent company guarantee was issued on behalf of ~~CARDÓN~~Cardón IV SA (Eni’s interest 50%), a joint venture ~~that is currently~~ operating ~~development activities at~~ the Perla gas field located in Venezuela, for the ~~supplying~~supply to PDVSA GAS of the volumes of gas produced by the field until ~~2036 (end~~the end of the concession ~~agreement)~~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 ~~amount of~~claim under the guarantee ~~execution~~ will be determined by applying the local legislation. ~~The Eni~~Eni’s share (50%) of the contractual volumes of gas to be delivered to PDVSA GAS amounted to a total of ~~$16 billion (€15.2 billion).~~around €13 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 ~~to Eni~~ by PDVSA ~~relating to~~on behalf of Eni for the fulfillment of the purchase commitments ~~relating to~~of the gas ~~quantities to be collected~~volumes by PDVSA GAS.

~~Following~~Other commitments also include the ~~integration signed on April 19, 2011, Eni confirmed~~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 RFI - Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) on October 15, 1991,2038, of carbon credits produced and certified according to guarantee a correct and timely execution of the section Milano-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as general contractor. In order to pledge the guarantee given, the regulation of CEPAV (Consorzio Eni per l’Alta Velocità) Due binds the associates to give proper sureties and guarantees on behalf of Eni.international standards by subjects specialized in forest conservation programs.

Eni is liable for certain non-quantifiable risks related to contractual assurances 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.

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~~Risk factors~~

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 of 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 ~~relation~~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. 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 ~~operations~~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’s~~Eni Corporate finance department, Eni Finance International SA and Eni Finance ~~International SA~~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. The commodity risk associated with commercial exposures of each business unit (Eni’s business line or subsidiaries) is pooled and managed by the Midstream business line, which manages the market risk component in a view of portfolio,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 ~~operations~~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 ~~the~~ 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 of 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

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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 onin the marketplace.

According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni ~~has~~ 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 ~~the~~ capital, manages such reserve and its immediate liquidity within the limits assigned. The management of strategic cash is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity.

The four different market risks, whose management and control have been summarized above, are described below.

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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 ~~the~~ euro (mainly ~~the~~ U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange ~~rates~~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 ~~the~~ euro are translated from their functional currency into euro. Generally, an appreciation of ~~the~~ U.S. dollar versus ~~the~~ 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 ~~the~~ 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 ~~central~~ finance ~~department,~~departments, which ~~pools~~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 ~~the~~ management’s finance plans. The Group’s ~~central~~ finance ~~department pools~~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. ~~Changes in fair value of those derivatives are normally recognized through the profit and loss account, as they do not meet the formal criteria to be accounted for under the hedge accounting method.~~ 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.

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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. 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 as 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 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 ~~finalized to~~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). InOrigination activities are included in the proprietary trading exposures, ~~are included the origination activities,~~ if not connected to contractual or physical assets.

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. ~~The~~Eni manages the commodity risk and the exposure to commodity prices fluctuations embedded in commodities quoted in currencies other than the euro at each business line (Eni’s Divisions or subsidiaries) is pooled and managed by the Portfolio Management unit for commodities, and by Eni’s finance department for exchange rate requirements. The Portfolio Management unit manages business lines’ risk exposures to commodities, pooling and optimizing Group companies’ exposures and hedging net exposures on the trading venues through the trading unit of Eni Trading & ~~Shipping. In order~~Shipping and the exposure to ~~manage~~ commodity ~~price risk, Eni uses~~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, ~~electricity~~power or emission certificates. Such derivatives are ~~evaluated~~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 ~~evaluated~~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~~governance guidelines regulating management and control systems. ~~The setting up and maintenance of the reserve of~~In particular, strategic liquidity is mainly aimed to: (i) guarantee of financial flexibility. Liquidity should allow Eni Group to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions); and (ii) ensure a full coverage of short-term debts and a coverage of medium and long-term financial debts due within a time horizon of 24 months, even in case of restrictions to credit.

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~~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 ~~and instruments to invest on.~~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 ~~years 2014 and 2015,~~year 2017 (U.S. dollar portfolio). In 2019, the Euro investment portfolio has maintained an average credit rating of A/A-/BBB+, ~~accordingly~~whereas the USD investment portfolio has maintained an average credit rating of A+/A, both in line with the ~~decrease in the Company’s credit rating.~~

year 2018. The following ~~table shows~~tables show amounts in terms of VaR, recorded in ~~2016~~2019 (compared with ~~2015)~~2018) relating to interest rate and exchange rate risks in the first section and commodity risk. Regarding the management of strategic liquidity, the sensitivity to ~~change~~changes of interest ~~rates~~rate is expressed by ~~the~~ values of “Dollar ~~Value~~value per Basis Point” (DVBP).

(Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%)


	2015								2016								2019								2018
(€ 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)		6.21		2.45		4.06		4.40		5.27		2.55		3.62		3.42		5.19		2.44		3.80		3.00		3.65		1.80		2.73		2.99
Exchange rate(a)		0.52		0.05		0.13		0.13		0.34		0.04		0.14		0.17		0.41		0.07		0.17		0.15		0.57		0.09		0.28		0.25

(a)

Value at risk deriving from interest and exchange rates exposures include the following finance ~~department:~~departments: Eni Corporate ~~Treasury~~Finance Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc.

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(Value at risk — Historic simulation ~~weighted~~ method; holding period: 1 day; confidence level: 95%)


	2015								2016								2019								2018
(€ 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)		61.91		3.37		26.82		3.37		19.03		4.23		10.24		9.41
Commercial exposures – Management Portfolio (a)																		23.03		7.74		11.22		9.11		18.60		6.79		11.04		7.50
Trading(b)		4.07		0.40		1.38		0.55		2.58		0.27		0.87		1.35		1.60		0.25		0.51		0.31		2.28		0.26		0.73		0.27

(a)

Refers to the ~~Midstream Department~~LNG Marketing & Power business line (risk exposure from Refining & Marketing ~~Division~~business line and Gas & Power Division), ~~Versalis,~~ Eni Trading & Shipping commercial portfolio, ~~and~~operating branches outside Italy pertaining to the ~~Divisions.~~Divisions and from October 2016 the Gas e Luce business line. For the ~~Midstream Department starting from 2014,~~Gas & Power 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, induring the year the VaR pertaining to ~~the Midstream Department~~GLP 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)


	2015								2016								2019								2018
(€ 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)		0.31		0.25		0.29		0.25		0.42		0.23		0.35		0.35		0.37		0.31		0.35		0.33		0.35		0.25		0.29		0.25

(a)

Management of strategic liquidity portfolio in € currency starting from July 2013.

(Sensitivity — Dollar value of 1 basis point — DVBP)


	2019								2018
($ million)	High		Low		Average		At year end		High		Low		Average		At year end
Strategic liquidity(b)		0.05		0.02		0.04		0.05		0.04		0.01		0.02		0.02

(b)

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. ~~The Group manages differently~~Eni defined credit risk ~~depending on whether~~management policies consistent with the nature and characteristics of the counterparties of commercial and financial transactions with regard to the centralized finance model. The Company adopted a model to quantify and control the credit risk ~~arises~~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 contracts on commodities related to Eni’s core business, 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 ~~exposure to financial~~commercial counterparties ~~or to customers relating to outstanding receivables. Individual~~is managed by the business units and ~~Eni’s~~by the specialized corporate finance and administration departments and is operated 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 and methods for quantifying and controlling customer risk, in particular for commercial counterparties, are assessed through an internal rating model that combines different default factors deriving from economic variables, financial indicators, payment experiences and ~~accounting units are responsible for managing credit~~information from 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 ~~arising in the normal course of the business.~~

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~~The Group has established formal credit systems and processes~~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 ~~ensure that before trading with a new counterpart can start, its creditworthiness is assessed. In addition, credit litigation and receivable collection activities are assessed.~~payments, periodically updated.

~~Eni’s corporate units define directions and methods~~Credit risk for ~~quantifying and controlling customer’s reliability.~~ 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 ~~guidelines prior~~internal policies providing exposure control and concentration through maximum credit risk limits corresponding to ~~entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile~~different classes of financial ~~activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of~~ counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the ~~Group~~Eni’s operating finance ~~department, including~~departments and Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and ~~Divisions,~~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 ~~to each counterparty~~ on a daily ~~basis.~~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 onin 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. ~~As part of its financial planning process, Eni manages~~Eni’s risk management targets include the ~~liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of~~ maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt in terms of: (i) maximum ratio between net financial debt and net equity (leverage); (ii) minimum incidence of medium and long-term debts over the total amount of financial debts; (iii) minimum amount of fixed-rate debts over the total amount of medium and long-term debts; and (iv) minimum level of liquidity reserve. For this purpose, Eni holds a significant amount of liquidity reserve (financial assets plus committed credit lines), which aims to: (i) ensure a full coverage of short-term debt and the coverage of medium and long-term debts with a maturity of 24 months, even in case of restrictions to the credit access; (ii) deal with identified risk factors that could significantly affect the cash flow expected in the Financial Plan (i.e. changes in the scenario and/or production volumes, delays in disposals); (iii) ensuring the availability of an adequate level of ~~financial~~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 ~~to support~~for the ~~Group’s~~ development ~~plans; and (iv) maintaining/improving~~programs of the ~~current credit rating.~~Company. The ~~financial asset~~strategic liquidity reserve is employed in short-term marketable financial instruments, favouring 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 financial assets and lines of credit and the access to a wide range of funding at competitive costs through the credit system and capital markets.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about ~~€16.3~~€14.9 billion were drawn as of December 31, ~~2016.~~2019.

The Group has credit ratings of ~~BBB+~~A- outlook stable and A-2, respectively, for long and short-term debt, ~~outlook stable,~~ assigned by Standard & ~~Poor’s and~~Poor’s; Baa1 outlook stable and P-2, respectively, for long and short-term debt, assigned by ~~Moody’s.~~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 ~~Standard & Poor’s and Moody’s,~~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, the rating of Eni remained unchanged.

In ~~the course of the 2016,~~2019, Eni issued bonds ~~amounting to €3.0 billion related to~~for €1,635 million, of which €746 million as part of the Euro Medium Term Notes ~~Program~~program and ~~equity-linked bonds~~€889 million through an issue amounting to ~~€0.4 billion.~~ $1 billion in the U.S. and international markets.

As of December 31, ~~2016,~~2019, Eni maintained short-term unused borrowing facilities of ~~€12,308 million, of which €41 million committed.~~€13,299 million. Long-term committed unused borrowing facilities amounted to ~~€6,236~~€4,667 million, of which ~~€700~~€450 million ~~were~~ due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.

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~~Finance debt repayments including expected~~Expected payments for ~~interest charges~~finance debts and ~~derivatives~~lease liabilities

The ~~table~~tables below ~~summarizes~~summarize the Group main contractual obligations for finance debt and lease liability repayments, including expected payments for interest charges and derivatives.

Maturity year
(€ million) 2016 2017 2018 2019 2020 2021 and
thereafter Total
December 31, 2015
Non-current financial liabilities 2,336 3,013 2,038 3,827 2,599 8,001 21,814
Current financial liabilities 5,720 5,720
Fair value of derivative instruments 4,261 56 1 33 8 4,359
12,317 3,069 2,039 3,860 2,599 8,009 31,893
Interest on finance debt 737 654 525 453 354 1,673 4,396
Financial guarantees 169 169

Maturity year
(€ million) 2017 2018 2019 2020 2021 2022 and
thereafter Total
December 31, 2016
Non-current financial liabilities 2,988 2,090 4,044 2,914 1,285 10,332 23,653
Current financial liabilities 3,396 3,396
Fair value of derivative instruments 2,108 36 76 46 3 2,269
8,492 2,126 4,120 2,914 1,331 10,335 29,318
Interest on finance debt 696 557 486 386 277 1,605 4,007
Financial guarantees 84 84

	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

~~Trade~~Liabilities for leased assets including related interest for €2,953 million refer to the share pertaining to the partners of unincorporated joint operations operated by Eni which will be recovered through recharges of cash calls.

Expected payments for trade and other 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

~~The table below summarizes the Group~~

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Expected payments under contractual obligations36

In addition to lease, financial, trade and other ~~payables by maturity.~~

Maturity year
(€ million) 2016 2017-2020 2021 and
thereafter Total
December 31, 2015
Trade payables 9,605 9,605
Other payables and advances 5,337 58 23 5,418
14,942 58 23 15,023

Maturity year
(€ million) 2017 2018-2021 2022 and
thereafter Total
December 31, 2016
Trade payables 11,038 11,038
Other payables and advances 5,665 29 22 5,716
16,703 29 22 16,754

~~Expected payments by period under~~liabilities represented in the balance sheet, the company is subject to non-cancellable contractual obligations

~~The Group has~~ or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in ~~place a number~~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 ~~obligations arising~~obligation and the contractual compensation/penalty in the ~~normal course~~event of ~~the business. To meet these commitments, the Group will have to make payments to third parties.~~ non-performance.

The Company’s main contractual obligations ~~pertain to~~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.

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The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

	Maturity year														Maturity year
(€ million)	2017		2018		2019		2020		2021		2022 and thereafter		Total		2020		2021		2022		2023		2024		2025 and thereafter		Total
Operating lease obligations(a)		593		353		257		231		199		785		2,418
Decommissioning liabilities(b)		253		580		417		400		184		14,447		16,281
Decommissioning liabilities(a)																331		325		163		179		424		12,052		13,474
Environmental liabilities		281		249		255		202		71		1,631		2,689		403		368		319		238		198		1,065		2,591
Purchase obligations(c)		10,891		9,265		9,511		8,839		7,961		73,758		120,225
Purchase obligations(b)																9,938		9,912		9,467		9,530		9,722		77,914		126,483
- Gas
- take-or-pay contracts		8,429		7,912		8,277		7,916		7,312		70,851		110,697		7,117		9,140		8,912		9,100		9,410		77,239		120,918
- ship-or-pay contracts		1,569		1,053		943		724		478		1,853		6,620		1,070		532		454		412		296		646		3,410
- Other take-or-pay or ship-or-pay obligations		114		105		101		96		80		228		724
- Other purchase obligations(d)		779		195		190		103		91		826		2,184
- Other purchase obligations																1,751		240		101		18		16		29		2,155
Other obligations		9		3		2		2		2		111		129		7		1								106		114
- Memorandum of intent relating Val d’Agri		9		3		2		2		2		111		129
		12,027		10,450		10,442		9,674		8,417		90,732		141,742

- Memorandum of intent – Val d’Agri																7		1								106		114
Total																10,679		10,606		9,949		9,947		10,344		91,137		142,662

(a)

Operating leases primarily regarded assets for drilling and production activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.

~~(b)~~

~~(c)~~(b)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.

~~(d)~~

~~Mainly refers to arrangements to purchase capacity entitlements at certain regasification facilities in the U.S. (€1,226 million).~~

Capital investment and capital expenditure commitments

In the next four years, Eni expects capital investments and capital expenditures of ~~€31.6~~€31.5 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.

Maturity year
(€ million) 2017 2018 2019 2020 2021 and
thereafter Total
Committed projects 6,733 6,679 4,218 2,441 3,685 23,756

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

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Contractual obligations related to employee benefits are indicated in note 21 — Provisions for employee benefits.

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Other information about financial instruments

The carrying amount of financial instruments and the relevant economic and equity effect ~~as of and for the years ended December 31, 2015 and 2016~~ consisted of the following:


	2015						2016							2019							2018
(€ 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			Other comprehensive income		Carrying amount		Profit and loss account			Other comprehensive income
Held-for-trading financial instruments
Securities(a)		5,028		3				6,166			(21)
Financial instruments at fair value with effects recognized in profit and loss acount
Financial assets held for trading(a)															6,760			127				6,552			32
Non-hedging and trading derivatives(b)		(921)		(327)				87			(465)				(125)			273				177			(178)
Held-to-maturity financial instruments
Securities(a)		77		1				75
Available-for-sale financial instruments
Securities(a)		282		8		(4)		238			9		(4)
Investments valued at fair value
Non-current investments(c)		368		286
Other investments valued at fair value(c)															929			247		(3)		919			231		15
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other(d)		19,946		(716)				17,324			(1,116)				12,926			(409)				14,145			(343)
Financing receivables(a)		3,256		(118)				2,328			128
Trade payables and other(e)		15,023		83				16,754			287
Financing payables(a)		27,793		(812)				27,239			(291)
Net assets (liabilities) for hedging derivatives(f)				(179)		(256)					(524)		883

Financing receivables(e)															1,503			110				1,489			(139)
Securities(a)															55							64
Trade payables and other(a)															15,699			33				16,902			(28)
Financing payables(f)															24,518			(802)				25,865			(615)
Net assets (liabilities) for hedging derivatives (g)															(2)			(739)		(679)					642		(243)

(a)

Income or expense were recognized in the profit and loss account within “Finance income (expense)”.

(b)

In the profit and loss account, economic effects were recognized as income within “Other operating income (loss)” for ~~€17~~€287 million ~~(loss~~(income for ~~€487~~€129 million in ~~2015)~~2018) and as loss within “Finance income (expense)” for ~~€482~~€14 million ~~(income~~(loss for ~~€160~~€307 million in ~~2015)~~2018).

(c)

InIncome or expense were recognized in the profit and loss account ~~economic effects were recognized as income~~ within “Income (expense) from ~~investments”~~investments — Dividends”.

(d)

InIncome or expense were recognized in the profit and loss account ~~economic effects were essentially recognized~~ as ~~expense~~net impairment losses within ~~“Purchase, services~~“Net (impairment losses) reversal of trade and ~~other”~~other receivables” for ~~€840~~€432 million ~~(expense~~(net impairment losses for ~~€641~~€415 million in ~~2015) (impairments net of reversal)~~2018) and as ~~expense for €276 million~~income within “Finance income (expense)” ~~(expense~~ for ~~€75~~€23 million (income for €69 million in ~~2015) (exchange~~2018), including interest income calculated on the basis of the effective interest rate ~~differences at year-end and amortized cost)~~of €26 million (interest income for €38 million in 2018).

(e)

In the profit and loss account, ~~exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end~~income or expense were ~~primarily~~ recognized as income within “Finance income (expense)”, including interest income calculated on the basis of the effective interest rate of €99 million (income for €129 million in 2018) and net revaluations for €4 million (net impairment losses for €275 million in 2018).

(f)

In the profit and loss account, income or expense were recognized as expense within ~~“Net sales~~“Finance income (expense)”, including interest expense calculated on the basis of the effective interest rate of €647 million (interest expense for €605 million in 2018).

��

(g)

In the profit and loss account, income or expense were recognized within “Sales from operations” and “Purchase, services and other” ~~as expense for €523 million (expense for €181 million in 2015) and as expense within “Finance income (expense)” for €1 million (income for €2 million in 2015) (time value component)~~.

Disclosures about the offsetting of financial instruments

~~The table below summarizes the 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		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, 2015
December 31, 2019
Financial assets
Trade and other receivables		22,351		711		21,640		13,773		900		12,873
Other current assets		6,052		2,410		3,642		4,584		612		3,972
Financial liabilities
Trade and other liabilities		15,653		711		14,942		16,445		900		15,545
Other current liabilities		7,122		2,410		4,712		7,758		612		7,146
December 31, 2016
December 31, 2018
Financial assets
Trade and other receivables		18,489		896		17,593		15,634		1,533		14,101
Other current assets		3,872		1,281		2,591		4,455		1,636		2,819
Financial liabilities
Trade and other liabilities		17,599		896		16,703		18,280		1,533		16,747
Other current liabilities		3,880		1,281		2,599		7,048		1,636		5,412

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The offsetting of financial assets and liabilities related ~~to: (i) for €1,281 million (€2,410 million at December 31, 2015)~~to the offsetting assets and liabilities for current financial derivatives pertaining to Eni Trading & Shipping SpA for €1,145 million (€2,389 million at December 31, 2015) and Eni Trading & Shipping Inc for €136 million (€21 million at December 31, 2015); and (ii) for €896 million (€711 million at December 31, 2015) the offsetting ofof: (i) receivables and payables pertaining to the Exploration & Production segment towards state entities for ~~€845~~€713 million (€~~664~~1,347 million at December 31, ~~2015)~~2018) and ~~the offsetting of~~ trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for ~~€51~~€187 million (€47186 million at December 31, ~~2015)~~2018); and (ii) other assets and liabilities for current financial derivatives of €612 million (€1,636 million at December 31, 2018).

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 3020 — Provisions ~~for contingencies~~ 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.

AIn 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 ~~paragraph.~~paragraphs. Unless otherwise indicated, 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.

1. Environment, health and safety

1.1 Criminal proceedings in the matters of environment, health and safety

(i) Eni Rewind SpA (former Syndial ~~SpA~~SpA) (company incorporating EniChem Agricoltura SpA -— Agricoltura SpA in liquidation -— EniChem Augusta Industriale Srl -— Fosfotec Srl) — Proceeding about the industrial site of Crotone. A In 2010 a criminal proceeding ~~is pending~~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 ~~subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrial~~takeover, any activity for waste ~~from Montedison activities until 1989 and then no additional waste~~conferral was ~~discharged there. Eni’s subsidiary carried out the clean-up of the landfill in 1999 through 2000.~~stopped. The defendants are certain managers ~~at Eni’s subsidiaries~~of Eni Group companies, that have ~~owned and~~ managed the landfill since 1991. ~~Independent consultants performed an assessment during~~The Municipality of Crotone is acting as plaintiff. In March 2019, the ~~2014. Once~~public prosecutor requested the ~~consultants completed their work, the acts returned to~~acquittal of all defendants. The proceeding is ongoing. In April 2017, the Public Prosecutor of Crotone started another criminal proceeding concerning the clean-up of the area called “Farina Trappeto”. The Company presented a new clean-up program already deemed approvable by the Ministry for the ~~next step and possible indictment.~~Environment. Clean-up remediation activities have started. The ~~proceeding continues with~~Company has requested the ~~examination~~dismissal of the ~~dismissal request submitted by the defense. The City of Crotone will act as offended party.~~second proceeding.

(ii) Eni Rewind SpA (former Syndial SpA) and Versalis SpA — ~~Industrial site~~Porto Torres — Prosecuting body: Public Prosecutor of ~~Praia a Mare.~~Sassari. ~~Based on complaints filed by certain offended persons,~~In 2011, the Public Prosecutor of Paola started an enquiry about alleged diseases related to tumors that those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. Based on the findings of independent appraisal reports, in the course of 2009 the Public Prosecutor resolvedSassari (Sardinia) determined that a ~~number~~manager responsible for plant operations at the site of ex-manager of that industrial complex would stand trial. In the preliminary hearing held in November 2010, 189 persons entered the trial as plaintiff; while 107 persons were declared as having been offended by the alleged crime. The plaintiffs have requested that both Eni and Marzotto SpA would bear civil liability. However, compensation for damages suffered by the offended persons has yet to be determined. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants wouldPorto Torres should stand trial for ~~culpable manslaughter, culpable injuries,~~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 ~~conduct about safety measures on~~behavior, replacing the ~~workplace. Following~~previous allegation of willful conduct. The Third Instance Court has denied a ~~settlement agreement with Eni, Marzotto SpA entered settlement agreements with all plaintiffs, except for~~motion to terminate the ~~local administrations. In December 2014, the Tribunal issued an acquittal sentence for all defendants, as the indictment was found groundless.~~proceedings. The Public Prosecutor ~~appealed against~~has re-submitted request that the ~~sentence.~~defendants stand trial. The proceeding is underway.

(iii) Eni Rewind SpA (former Syndial ~~SpA~~SpA) and Versalis SpA — Porto Torres dock. In ~~July~~ 2012, ~~the Judge for the Preliminary Hearing,~~ following a request of the Public Prosecutor of Sassari, ~~requested the performance~~an Italian court ordered presentation of ~~a probationary~~ evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by

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~~Syndial~~ Eni Rewind SpA) and its capacity to avoid the dispersion of contamination released by the site ininto the ~~near portion of~~nearby sea. ~~Syndial~~Eni Rewind SpA and Versalis SpA ~~have been~~were notified that its chief executive officers and certain other managers ~~are~~were being investigated. The Public Prosecutor of the Municipality of Sassari requested that ~~the above-mentioned~~these individuals ~~would~~ stand trial. The ~~Judge~~plaintiffs, the Ministry for preliminary investigation authorized that the two Eni’s subsidiaries would be arraigned to compensate any possible damage in connection with the proceeding. The trial was held with an abbreviated procedure. The plaintiffs Ministry of Environment and the Sardinia Region claimed environmental damage in an amount of ~~€1 billion and €500 million, respectively. On~~€1.5 billion. Other parties referred to the judge’s equitable assessment. At a hearing ~~dated~~in July ~~22,~~ 2016, the ~~Judge pronounced an acquittal sentence for Syndial~~court acquitted all defendants of Eni Rewind and ~~Versalis. Certain~~Versalis with respect to the crimes of ~~Eni’s employees~~environmental disaster. Three Eni Rewind managers were found ~~guilty: the environmental manager~~guilty of ~~the area, the environmental manager of Porto Torres site and the manager in charge of the Syndial’s groundwater treatment plant, who were all condemned to one year, with a suspended sentence, for~~ environmental disaster ~~which took place in the area in~~relating to the period limited to August 2010 – January ~~2011. The provisional settlement awards compensation payment of €200,000~~2011 and sentenced to the Ministry, €100,000 to the Sardinia Region and €100,000 to the Municipality of Sassari. The Judge did not mention any possible malfunctioning of the hydraulic barrier of Porto Torres site or ineffective implementation of any emergency safety measure, as claimed by the Public Prosecutor. Syndial will fileone-year prison, with a suspended sentence. Eni Rewind filed an appeal against this decision. The proceeding is underway.

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(iv) Eni Rewind SpA (former Syndial ~~SpA -~~SpA) — The illegal landfill in Minciaredda area, Porto Torres site. ~~On July 7, 2015, the Judge for the Preliminary Hearing of the~~The Court of Sassari, on request of the Public Prosecutor, ~~decided the seizure of~~seized the Minciaredda landfill area, near the western border of the Porto Torres ~~site.~~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 ~~provision~~order involved ~~as well Syndial in accordance with the~~also Eni Rewind pursuant to Legislative ~~Degree~~Decree No. ~~231 of 2001 that held~~231/01, whereby companies are liable for the crimes committed by their ~~employees.~~employees when performing their duties. The ~~investigations are underway. With a reference to~~court determined that Eni Rewind can be sued for civil liability and resolved that all defendants and the ~~clean-up activities in~~Eni subsidiary be put on trial before the Minciaredda area, on January 27, 2016 the administrative body responsible for sanctioning clean-up projects approved: i) the operative project “Nuraghe” which provides for the soil clean-up in the area “Peci” (depositCourt of pitch from dimethyl terephthalate – DMT) and in the area “Palte Fosfatiche” (phosphates deposit) in the Minciaredda area; and ii) an addendum to the operative project of clean-up of the groundwater in the Minciaredda area. Syndial obtained the necessary ministerial and judicial authorizations to start the remediation project. The investigations are underway.Sassari.

(v) Eni Rewind SpA (former Syndial ~~SpA -~~SpA) — The Phosphate deposit at Porto Torres site (1). ~~On June 30,~~In 2015, ~~the Judge for the Preliminary Hearing of~~ the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, ~~sentenced to seize~~seized — as a preventive measure — the area of “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster, ~~and~~ carrying out anof unauthorized disposal of hazardous ~~wastes. Subsequently~~wastes and other environmental crimes. Eni Rewind SpA is being investigated pursuant to Legislative Decree No. 231/01. In November 2019, a ~~specific~~ request ~~both~~for referral to trial was served on the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari authorized to implement better delimitation of the landfill area, to provide the area with devices to monitor the level of environmental pollutants and meteoric waters. The investigations are underway.Eni subsidiary.

(vi) Eni Rewind SpA (former Syndial ~~SpA -~~SpA) — Phosphate deposit at Porto Torres site (2). ~~On December 16,~~In 2015, the Public Prosecutor at the Court of Sassari ~~sentenced to seize~~seized — as a probative measure — the containment systems for the meteoric waters in the area “Palte Fosfatiche” (phosphates deposit)~~. These waters are being collected by Syndial following authorizations~~, located on the territory of ~~the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari.~~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 and spill of waters containing hazardous substances. The Public Prosecutor decided to suspend~~waste. This investigation has been combined into the activities of collection, containment and preservation of the area, in spite that those activities have already been authorized. Syndial filed a request to continue conducting clean-up operations to the Judge for the Preliminary Hearing of the Court of Sassari. The investigations are underway.abovementioned one.

(vii) Eni Rewind SpA (former Syndial ~~SpA - Public Prosecutor of Gela.~~ An investigation is pending before the Public Prosecutor of Gela regarding 17 former managers of the Eni Group. The proceeding regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged work-related diseases that those persons may have contracted at the plant of Clorosoda. Alleged crimes relate to the period from 1969, when the Clorosoda plant commenced operations till 1998 when the plant was shut down and clean-up activities were performed. The Public Prosecutor requested the performance of a medico-legal appraisal on over 100 people that were employed at the above-mentioned plant. This appraisal was performed by independent consultants designated by the Judge for preliminary investigation

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and did not find any evidence that the various diseases which underwent the medical appraisal could be directly linked to the exposure to emissions related to the production of chlorine and caustic soda. The consultants also found that production activities were in compliance with applicable laws and regulations on health and safety. On January 23, 2015, the Judge for preliminary investigation declared that the gathering of evidence before a trial was concluded. The Public Prosecutor issued a notice of the conclusion of preliminary investigations deciding not to ask for dismiss of charges only in relation to the one specific case, which regards one former employee which in the meantime had died, compared to the initial complaint that concerned several (over a hundred) cases of personal injury and manslaughter. Therefore, the proceeding has been downsized compared to the initial claim. The rest of the accusatory assumptions, however, seems to be groundless in the light of the results of assessment performed by independent consultants appointed by the Judge for the preliminary investigation. The criminal proceeding is still pending.

~~(viii) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria~~SpA) — ~~Prosecuting body: Public Prosecutor of Castrovillari.~~ Certain areas owned by Eni in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria have been preventively seized by the Judicial Authority, following a pending investigation about an alleged improper handling of industrial waste from the processing of zinc ferrites at the industrial site of Pertusola Sud, alleged illegally stored. The circumstances under investigation are the same considered in a criminal action for alleged omitted clean-up that was concluded in 2008 without any negative outcome on part of Eni’s employees. Eni’s subsidiary Syndial SpA has removed any waste materials from the landfills. Besides that, Syndial defined an agreement with the Municipality of Cerchiara and the Municipality of Cassano to settle all claimsProceeding relating to alleged damages caused by the unauthorized waste disposal in the landfills on the territory of the two Municipalities. The criminal proceeding is still pending. The remediation activities have been completed and the company filed a memorandum to request the closing of the proceeding.

~~(ix) Syndial SpA - Proceeding on~~ the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna ~~about~~relating to the crimes of culpable manslaughter, injuries and environmental disaster, which ~~would~~ have been allegedly committed by former ~~Syndial~~Eni Rewind employees at the site of Ravenna. The site was ~~taken over~~acquired by ~~Syndial~~Eni Rewind following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are ~~77 affected~~75 alleged victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. ~~The advocacy of Syndial claimed~~Eni Rewind asserted the statute of limitation ~~about~~as a defense to the instance of environmental disaster for certain instances of diseases and deaths. The ~~Judge for the Preliminary Hearing~~court at Ravenna decided that all defendants would stand trial and ~~ascertained~~held that the statute of limitation only applied with reference to certain instances of crime of culpable injury. ~~Concluded the trial, the proceeding entered the hearing phase for the final discussion. Syndial has signed~~Eni Rewind reached some settlements. OnIn November ~~24,~~ 2016, the Judge ~~lifted~~acquitted the ~~reserve, acquitted~~defendants in all the ~~accused~~contested cases except for 76one, an asbestos case, for which a conviction was handed down. The defendants, the prosecutor and the plaintiffs appealed the decision. The second instance Judge ordered a complex report, and stated that they could not decide the appeal at that stage of the ~~77 contested cases~~proceedings, and ~~sentenced 6 of~~appointed three experts. The proceeding is ongoing before the ~~15 defendants for a single case of asbestosis.~~appeals Court.

~~(x)~~(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. ~~Raffineria di~~The Gela ~~SpA~~Refinery has been ~~sued~~prosecuted for administrative offence ~~in accordance with the Law~~pursuant to Legislative Decree No. ~~231 of 2001.~~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, ~~in addition to the~~and pollution of the sea water near the ~~coast~~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. OnAt the ~~closure~~closing of the preliminary investigation, the Public Prosecutor of Gela ~~reunited in~~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 ~~still pending.~~ongoing.

~~(xi) Proceeding~~(ix) Val d’Agri. ~~The Italian~~In March 2016, the Public ~~Prosecutor’s Office~~Prosecutors of Potenza started a criminal investigation ~~in order to ascertain existence of an~~into alleged illegal handling of ~~wastes~~waste material produced at the Viggiano oil center (COVA), part of the Eni-operated Val d’Agri oil ~~complex, and disposed at treatment plants in the national territory.~~complex. After a two-year investigation, the Prosecutors ~~decided for~~ordered the ~~domiciliary detention~~house arrest of 5 Eni employees and ~~to put under~~the seizure of certain plants functional to the production activity of the Val d’Agri complex which, ~~as a consequences,~~consequently, was shut down ~~(60 kboe/~~(loss of 60 KBOE/d net to Eni)~~, to be then resumed on 10 August 2016.~~. From the commencement of the investigation, Eni has carried out several ~~and in-depth~~

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technical and environmental surveys, with the support of independent experts of international ~~reach,~~standing, who ~~recognized~~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 ~~sought to obtain a repeal of the seizure before the jurisdictional authorities without an outcome. The Company studied~~implemented certain corrective measures to upgrade plants which ~~although being not a structural solution,~~ were intended to address the claims made by the public prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those ~~measures comprise building a gathering system of waters associated with the extraction of hydrocarbons at the gas lines. Those~~ corrective measures were ~~favourably~~favorably reviewed by the ~~public prosecutor, who granted~~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 and the Company. The Prosecutor requested Eni ~~a temporary repeal~~and all the defendants be put on trial, pursuant to Legislative Decree No. 231/01. The trial started in November 2017 and is ongoing.

(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 ~~seizure~~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 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 plan for the internal and external areas of the COVA, whose final report was examined by the relevant authorities. Following this event, a criminal investigation was initiated in order to ~~allow~~ascertain whether there had been illegal environmental pollution by the ~~Company perform~~former COVA officers, the ~~works. The in-charge department~~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 to certain 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 ~~Ministry~~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 ~~Economic Development duly authorized~~serious danger to human health and the ~~works~~environment. In April 2019, precautionary measures were ordered against three Eni employees at the COVA. 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.

(xii) Raffineria di Gela SpA and ~~established~~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 ~~strict schedule~~criminal proceeding relating to ~~execute~~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 against the CEO of the Refinery of Gela SpA and of the company itself has been dismissed, while the CEO of Enimed SpA and the company were requested to be put on trial. The proceeding is ongoing.

(xiii) Eni Rewind SpA (former Syndial SpA) — Environmental disaster at Ferrandina. In January 2018, the Public Prosecutor of Matera commenced a criminal proceeding against a manager of the Eni subsidiary Eni Rewind based on allegations of unlawful handling of waste and environmental disaster as part of the

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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 due to a damaged pipe dedicated to the transportation of effluent to a disposal plant ~~upgrading~~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.

(xiv) 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 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. The plant modification works were completed~~Public Prosecutor and his consultants. Based on ~~July 10, 2016 and on July 20, 2016,~~this, an appeal was filed against the ~~Carabinieri~~measure of NOE, assisted by the Technical Consultant of the Prosecutor, conducted the inspection to verify the state of the site and the compliance of the correct execution of the plant upgrading. Following the report prepared by the Technical Consultant, as a consequence of the inspection conducted, the Prosecutor issued the decision for the definitive release fromprecautionary seizure of the plant ~~while~~before a review court, which revoked the ~~Region took note~~seizure of the ~~measure~~plants on March 26, 2019.

(xv) 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 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 ~~part~~crimes committed by employees in a number of ~~competence. On August 10, 2016,~~matters, including the ~~plant was restarted with re-injection into the well Costa Molina 2. Simultaneously with the restart~~violations of laws about safety of the ~~plant, the Company began the review procedure at AIA by presenting the documents within the deadline of 14 August 2016.~~workplace. The proceeding is ongoing.

(xvi) 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 ~~preliminary hearings.~~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) Eni Rewind SpA (former Syndial SpA) and Versalis — Mantua. Environmental crime investigation. The Public Prosecutor of Mantua has initiated a series of proceedings against companies of the Eni group and employees of Eni for alleged environmental crimes related to the Mantua industrial hub. Investigations, whose terms have been extended, are in progress. The Prosecutor of Mantua is proceeding for the crime of omitted clean-up, both according to the case foreseen by the Consolidated Environmental Text and for the hypothesis foreseen by the penal code “up to the present”. Eni companies are being investigated pursuant to Legislative Decree No. 231/01.

1.2 Civil and administrative proceedings in the matters of environment, health and safety

(i) Eni Rewind SpA (former Syndial ~~SpA -~~SpA) — Summon for alleged environmental damage caused by DDT pollution in the Lake ~~Maggiore - Prosecuting body: Ministry of the Environment.~~Maggiore. In May 2003, the Ministry offor the Environment ~~summoned Syndial to obtain a sentence condemning the~~claimed compensation from Eni ~~subsidiary to compensate an~~Rewind for alleged environmental damage caused by the activity ofat the Pieve Vergonte plant in the years 1990 through 1996. ~~With a temporarily executive sentence dated~~In July 3, 2008, the District Court of Turin ~~sentenced the subsidiary Syndial SpA~~ordered Eni Rewind to ~~compensate~~pay environmental damages amounting to €1,833.5 million, plus ~~legal costs that~~interests accrued from the filing of the

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decision. Syndial and Eni technical legal consultants have considered the decision and the amount of the compensation to be without factual and legal basis and have concluded that a negative outcome of this proceeding is unlikely. Particularly, Eni and its subsidiary ~~deem~~deemed the amount of the environmental damage to be absolutely groundless as the sentence ~~lacks~~lacked sufficient elements to support such a material amount of the liability ~~charged to Eni and its subsidiary with respect to~~from the volume of pollutants ascertained by the Italian Environmental Minister. ~~Based on these technical legal advices, which is also supported by external accounting consultants, no provisions have been made with respect to the proceeding.~~ In July 2009, ~~Syndial~~Eni Rewind filed an appeal ~~against the above-mentioned sentence,~~ and consequently the proceeding continued before a Second ~~Degree Court of Turin. In the hearing of June 15, 2012, before the Second Degree~~Instance Court of Turin the Minister of the Environment, formalized trough the Board of State Lawyers its decision to not enforce the sentence until a final verdict on the matter is reached. The Second Degree Court requested Syndial to stand as defendant and thenthat requested a technical appraisal ofon the matter. This technical appraisal was favorable to Syndial; however, the Board of State Lawyers questioned such outcome. On July 8, 2015, the Court of Appeal of Turin requested the consultants appointed by the Court to perform again a technical appraisal of the matter with aim to identify adequate measures for environmental restoration of the external areas. On June 13, 2016, the consultants filed an integration to the technical appraisal. In brief, the consultants validated the technical review of the matter and other technical assessments which were carried out by the Company together with local and national technical entities. 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 ~~and the usability~~ of the ecosystem, therefore no restoration or damage compensation should be ~~claimed. The~~claimed; the only impact ~~which could be recorded concerns~~seen concerned fishing activity, with an estimated damage of €7 million which ~~can~~could be already restored ~~by means of~~through the measures proposed by ~~Syndial;~~Eni Rewind, and; (iii) the necessity and convenience of dredging should be ~~definitely~~ excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the ~~Syndial’s~~Eni Rewind’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. OnIn March 6, 2017, ~~a second-degree Court issued a sentence repealing~~ the ~~first-degree court verdict, which had sentenced Syndial to compensate environmental damage in excess~~Second Instance Court: (i) excluded the application of compensation for monetary equivalent; (ii) annulled the monetary compensation of €1.8 ~~billion. The second-degree Court reaffirmed that monetary compensation is no longer applicable and requested Syndial~~billion requesting Eni Rewind to perform the already approved ~~cleanup~~clean-up project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The

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value of these compensatory works ~~requested~~required by the Court, in case of ~~Syndial~~Eni Rewind failure ~~to perform~~ or misperformance, is estimated at €9.5 million. The ~~cleanup~~clean-up project ~~was~~ filed by ~~Syndial,~~Eni Rewind was ratified by ~~local and governmental~~the authorities and is currently being executed. Expenditures expected to be incurred ~~by Syndial~~ have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were ~~rejected.~~

~~(ii)~~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, the Company and its managers filed an appeal and a counter-appeal.

(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 ~~running~~operating plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Versalis, Syndial 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~~above-mentioned companies ~~opposed said~~contested these administrative actions, objecting in particular to the ~~way in which~~nature of the remediation works ~~have been designed~~decided and ~~modes~~the methods whereby information on the pollutants concentration has been gathered. A number of administrative proceedings ~~were~~ started on this matter ~~which~~ were ~~reunified~~subsequently merged before the Regional Administrative ~~Court of Catania.~~Court. In October 2012, ~~said~~the Court ruled in favor of Eni’s subsidiaries against the ~~Ministry prescriptions about~~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. The ~~proceeding~~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. A report of the committee affirmed the 2017 warning of the Ministry and reaffirmed the State agencies and local administrations’ view as to the environmental liability to be charged to the companies operating in the area. In coordination with the other companies operating at the site, the report is ~~still pending.~~being appealed and further technical analyses have been commenced 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.

(iii) Eni SpA — Eni Rewind SpA (former Syndial SpA) — Raffineria di Gela SpA — Claim for preventive technical ~~inquiry - Court of Gela.~~inquiry. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and ~~Syndial~~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 33the parents of children ~~born malformed~~with birth defects in the Municipality of Gela between 1992 and 2007. The claim called for ~~preventive technical~~an inquiry ~~aims~~aimed at ~~verifying the relation of~~determining any causality between the ~~malformation pathologies~~birth defects suffered by ~~the~~these children ~~of the plaintiffs~~ and ~~the~~any environmental pollution caused by the Gela site, ~~(pollution deriving from the existence and activities at the industrial plants of Raffineria di Gela SpA and Syndial SpA),~~ quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. ~~In any case, the~~The same issue was the subject of previous criminal proceedings, of which one closed without ~~ascertainment of~~determining any ~~illicit~~illegal behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. The consultants appointed by the Court and those designated by the plaintiffs performed a technical appraisal of the matter, reaching however very different outcomes. Thus, parties failed to reach a settlement of the matter. OnIn December ~~22,~~ 2015, the three ~~involved Eni~~ companies ~~were sued following a claim of the parents of a girl, whose case was assessed by the above-mentioned technical appraisal. Subsequently, the Eni’s companies~~involved were sued in relation to ~~other~~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 ~~proceeding is pending.~~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 - Plaintiffs:~~Cengio. Since 2008 a proceeding is pending by the Court of Genoa, brought by the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio. ~~The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio~~ Those parties summoned ~~Eni’s subsidiary Syndial~~Eni Rewind before a Civil Court and ~~sentenced the~~demanded Eni’s subsidiary to 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 ~~Syndial~~Eni Rewind of negligence in performing the clean-up and remediation of the site. ~~On the contrary, Syndial believes they have executed the clean-up work properly and efficiently in accordance with the framework agreement signed with the involved administrations including~~In March 2019, the Ministry for the Environment presented a proposal to Syndial to settle the case. The Company responded with a counter-proposal in July 2019. The judge is verifying the progress and status of the Environment in 2000. On February 6, 2013, a Court in Genoa ruled the resumption of the proceeding and established a technical appraisal to verify the existence of the environmental damage. Following failed attempts to define a settlement agreement of the matter among the involved parties, the Judge resumed the trial. The next stop in the procedure is the performance of an independent appraisal of the matter by a consultant appointed by the Judge.negotiations.

(v) Eni Rewind SpA (former Syndial ~~SpA and Versalis SpA — Porto Torres — Prosecuting body: Public Prosecutor of Sassari.~~ The Public Prosecutor of Sassari (Sardinia) resolved that a number of officers and senior managers of companies engaging in petrochemical operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s fully-owned subsidiary Syndial, would stand trial due to allegations of environmental damage and poisoning of water and crops. The Province of Sassari, the Municipality of Porto Torres and other entities have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine

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fauna of the industrial port of Porto Torres. The proceeding continues before the Prosecutor of Sassari. In February 2013, the Prosecutor of Sassari has notified the conclusion of preliminary investigations and requested a new imputation for negligent behaviour instead of illicit conduct. In the conclusions of the preliminary hearing, the GUP of Sassari dismissed the accusation because of the statute of limitations. The Public Prosecutor filed an appeal before a Third Instance Court. After a hearing on a question of constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the Constitutional Court.

~~(vi) Syndial SpA~~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 ~~Syndial~~Eni Rewind and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff ~~claimed the responsibilities of Syndial~~alleged Eni Rewind and Versalis ~~for~~were responsible because they produced the ~~production of~~ waste and ~~because they~~ commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to ~~2001-2003~~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~~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 (this landfill is located about 2 kilometers from the town~~party. Two subsidiaries of ~~Melilli). The claim amounts~~Eni and a third-party waste company were claimed to ~~€500 million and refers to two Group’s subsidiaries and SMA.RI, the company that carries out activities of waste disposal, being~~be jointly and severally ~~liable. On February 8, 2016,~~liable for damage amounting to €500 million. The third-party company executed waste disposal at the site. In June 2017, the Judge accepted ~~an explanation of Eni’s subsidiaries stating that the request of municipality was not admissible, so that the request was rejected. The proceeding is still pending.~~

~~(vii) Summon for Eni, Raffineria di Gela SpA, EniMed SpA and Syndial SpA.~~ ~~273 Gela residents filed an appeal to the Court of Gela requesting to halt~~ all the ~~production activities conducted by Eni’s subsidiaries at Gela site in order to put an end to environmental pollution affecting~~defensive instances of Eni Rewind and Versalis, judging the ~~health~~requests of the ~~local population. The claimants~~Municipality to be inadmissible for lacking right to sue, also ~~requested~~considering the ~~appointment of commissioners in charge of carrying out the plants shutdown~~requests to be unfounded or unproved, and ~~of continuing to implement clean-up activities in the area. Besides that, they requested the Court to order to~~ordered the Municipality ~~of Gela — as a competent body in~~to refund the field of health protection — to adopt certain provisions aimed to preserve the health of the local population. This proceeding arose in connection with an alleged environmental damage caused by the industrial activities of the site and consequent necessity to protect the population from serious harm to the health. The initiative was underpinned by certain technical assessments performed by consultants appointed by the Court on the preliminary stage. The aim of these assessments was to establish cause-and-effect relationship between the industrial contamination and congenital anomalies reported in the town of Gela.

~~2. Court inquiries and of other Regulatory Authorities~~

~~(i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration.~~ On January 23, 2013, the Italian airline company Alitalia which was undergoing a reorganization procedure, summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to obtain a compensation for alleged damages caused by a presumed 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 deliberation filed by the Italian Antitrust Authority on June 14, 2006. The antitrust deliberation accused Eni and other 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. The antitrust findings were substantially endorsed by an administrative court. Alitalia has made a claim against the three petroleum companies jointly and severally presenting two alternative ways to assess the alleged damages. A first assessment of the overall damages amounted to €908 million. This was based on the presumption that the anti-competitive agreements among the defendants would have prevented Alitalia from autonomously purchasing supplies of jet fuel in the years when the existence of the anti-competitive agreements were ascertained by the Italian Antitrust Authority and in subsequent years until Alitalia ceased to operate airline activity. Alitalia asserts the incurrence of higher supply costs of jet fuel of €777 million excluding interest accrued and other items which add to the lower profitability caused by a reduced competitive position in the marketplace estimated at €131 million. An alternative assessment of the overall damage made by Alitalia stands at €395 million of which €334 million of higher purchase costs for jet fuel and €61

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million of lower profitability due to the reduced competitive position on the marketplace. With a decision dated May 23, 2014, the Court of Rome declared the connection with a judgment previously proposed by Alitalia itself before the Court of Milan against other oil companies participating to an alleged cartel agreement. The case was thus summed up by Alitalia before the Court of Milan. The proceedings is still pending before the First Degree Court. Eni accrued a risk provision against this proceeding.

~~(ii) 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. An arbitration award of June 23, 2016 dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considers that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra now claims an additional amount to be paid by Eni which corresponds to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, does not agree with GasTerra’s interpretation and regards GasTerra claim groundless. However, GasTerra, based on its own interpretation, commenced arbitration proceedings and obtained from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV, for the alleged trade receivable due by Eni (equal to €1.01 billion). This measure, which was granted after a summary review only and without Eni being heard, does not prejudice the outcome on the meritsexpenses of the proceeding. In ~~order to obtain~~April 2018, the ~~discharge~~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 ~~seizure~~Val d’Agri area, who are complaining of economic, non-economic, biological and moral damages, all deriving from the presence of Eni’s ~~investment~~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 ~~International BV, Eni proposed~~be ordered to ~~GasTerra~~interrupt any polluting activity and to ~~replace~~be allowed to resume industrial activities on condition that all the ~~seizure with a bank guarantee~~necessary remediation measures be implemented to eliminate all of the ~~same amount as~~alleged dangerous situations. Finally, they are asking that Eni compensate all direct and indirect property damages, current and future, to an extent to be quantified during the ~~GasTerra claim, which would remain effective until~~proceedings.

(vii) Eni Spa — Climate change. In 2017 and 2018, local government authorities and a fishing association brought in the ~~arbitration final award. GasTerra accepted Eni’s offer. With the filing~~courts of the ~~Stetement~~State of ~~Defense~~California seven proceedings against Eni Group companies and ~~Counterclaim, Eni will~~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 that the arbitration panel states the provisional price established in the Agreement Letter continues being applied until a new contractual price is defined with retroactive efficacy from 2012, based on trends recorded in the Italian market. Currently it not possible to estimate a time schedule of the ~~arbitration procedure because~~defendants, from the ~~panel~~State Courts to the Federal Courts. A specific request has ~~yet to be appointed. Presumably, a decision about~~been filed, highlighting the ~~first award interpretation or about the interpretation~~lack of jurisdiction of the ~~Agreement Letter will not occur before the end of 2017 or the beginning of 2018. Eni will further seek compensation~~State Courts. The proceedings are currently suspended and waiting for any damages it incurs, due to GasTerra’s legal actions. At the present, there are no evidence to suggest that an upward revision of the provisional price is likely. Furthermore, Eni is part to another arbitration proceeding relating to the price revision of a ~~long-term gas supply contract.~~jurisdictional competence.

~~3. Court inquiries on the matter of~~2. Proceedings concerning criminal/administrative corporate responsibility

(i) EniPower SpA. In ~~June~~ 2004, the ~~Milan~~ Public Prosecutor of Milan commenced inquiries into contracts awarded by Eni’s subsidiary EniPower SpA and onas to supplies ~~from~~provided by other companies to ~~EniPower.~~EniPower SpA. It emerged that illicit payments were made by EniPower SpA suppliers to a manager of EniPower SpA who was immediately ~~dismissed.~~fired. The Court served EniPower SpA (the commissioning entity) and

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Snamprogetti ~~(now~~SpA, now Saipem ~~SpA)~~SpA (contractor of engineering and procurement services), with notices of investigation ~~in accordance with~~pursuant to Legislative Decree No. 231/~~2001 that establishes that companies are liable for the crimes committed by their employees who acted on behalf of the employer.~~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 ~~under the provisions of~~pursuant to Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the Preliminary Hearings requested all the parties that have not requested the plea-bargain to stand in trial, excluding certain defendants as a result of the statute of limitations. During the hearing on March 2, 2010, the Court confirmed the admission as plaintiffs of01. Eni SpA, EniPower SpA and ~~Saipem~~Snamprogetti SpA ~~against the inquired parts under the provisions of Legislative Decree No. 231/2001. Further employees of the companies involved were identified~~presented themselves as ~~defendants to account for their civil responsibility.~~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 ~~dedicated~~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 ~~individuals.~~defendants. In ~~relation~~reference to the ~~companies~~parts involved in the proceeding pursuant to Legislative Decree No. 231/01, the Court found that 7 companies are ~~liable based on~~responsible for the ~~provisions of Legislative Decree No. 231/2001,~~

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administrative offenses ascribed to them, imposing a fine and the disgorgement of profit. ~~Eni SpA and its subsidiaries, EniPower and Saipem, which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies.~~ The Court rejected the position as plaintiffs of the Eni Group companies, reversing athe prior decision made by the Court. This decision may have been made based on a pronouncement made by a ~~Supreme~~Third Instance Court that stated the illegitimacy of the constitution as plaintiffs ~~made~~ against any legal entity, ~~which is~~as indicted ~~under the provisions of~~pursuant to Legislative Decree No. 231/~~2001.~~01. The ~~Court filed the ground of the judgment in December 19, 2011. The condemned~~sentenced parties filed an 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. ~~In 2015, the Supreme~~The Third Instance Court successively annulled the judgment of the ~~Appeal~~Second Instance Court ~~of Milan~~ ascribing the judgment to another ~~section.~~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 ~~its~~Eni’s former ~~controlled company~~subsidiary Saipem in Algeria. ~~On February 4,~~In 2011, Eni received from the Public Prosecutor of Milan an information request ~~pursuant to Article 248 of~~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). ~~For that reason, Eni forwarded the notification to Saipem.~~ The crime of international corruption is among the offenses ~~contemplated by~~pursuant to Legislative Decree ~~of June 8, 2001,~~ No. ~~231, relating to~~231/01, which provides for corporate ~~responsibility~~liability for crimes committed by employees ~~which provides~~and prescribes punishments including fines ~~and interdictions to the company~~ and the disgorgement of profit. ~~Saipem promptly began to collect documentation in response~~Eni also voluntarily provided to the ~~requests of the~~ Public ~~Prosecutor. The documents were produced on February 16, 2011. Eni also filed~~Prosecutor documentation relating to the MLE project (in which ~~the~~ Eni’s Exploration & Production Division participates) ~~even if not required,~~, with respect to which investigations in Algeria are ongoing. OnIn November ~~22,~~ 2012, the Public Prosecutor ~~of Milan~~ served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption ~~in accordance~~pursuant to ~~Article 25, second and third paragraph of~~ Legislative Decree No. 231/~~2001.~~01. Furthermore, the Public Prosecutor requested the production of certain documents relating to certain activities in Algeria. ~~The proceeding was unified with~~Subsequently, the ~~Iraq-Kazakhstan proceeding, concerning a different line of investigation, as it related~~Public Prosecutor’s Office notified further measures and requests to ~~the activities carried out by Eni in Iraq and Kazakhstan. Subsequently~~ Saipem, ~~was served a notice of seizure, then a request for documentation and finally a search warrant was issued, in order to acquire~~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, ~~who~~the employment of whom was ~~fired~~terminated at the beginning of 2013. OnIn February 7, 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 ~~in accordance with Article 25, third and fourth paragraph of~~pursuant to Legislative Decree No. 231/~~2001~~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 ~~team~~ to the Algerian matters. ~~During 2013, the~~The external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department ~~have~~did not ~~found~~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 ~~a voluntary basis of~~ the MLE project, the only project that Eni understands to be under the prosecutors’

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investigation where the client is an Eni Group company ~~has~~did not ~~found~~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). 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, ~~and~~ accounting and administrative issues. The findings of ~~the~~that review ~~performed have~~ confirmed the autonomy of Saipem from the parent ~~company.~~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. On October 24, 2014, Eni SpA received a request of probationary evidence by the Prosecutor of Milan relating to for the examination of two defendants: the former Chief Operating Officer of the Business Unit

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~~Engineering & Construction of Saipem and the former President and General Manager of Saipem Contracting Algérie SpA. On~~In January ~~14,~~ 2015, the Public Prosecutor ~~of Milan~~ notified the conclusion of preliminary investigations ~~towards~~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 ~~of Milan has~~ issued a notice ~~for~~of alleged international corruption against all ~~defendants~~such persons (including Eni SpA and Saipem ~~on the base of the provisions of~~SpA pursuant to Legislative Decree No. 231/~~2001)~~01) in connection with the entry into intermediary contracts by Saipem in Algeria. Furthermore, some of the defendants (including the former CEO and CFO of Eni and the Chief Upstream Officer of Eni) were accused of tax offense for fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. Having acquired the actions of the court filed in relation to the request of probationary evidence, the minutes of the hearing and the documents filed for the conclusion of the preliminary investigation, Eni requested its consultants to perform additional analysis and investigation. As a result, Eni’s consultants reaffirmed their conclusions previously reported to the Company. In February 2015, the Public Prosecutor ~~indicted~~requested the indictment of all the investigated persons for ~~above-mentioned crimes. On October 2,~~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 ~~crimes. On~~offenses. In February ~~24,~~ 2016, the ~~Court of~~ Third Instance Court, upholding an appeal presented by the Public Prosecutor, ~~of Milan,~~ reversed the dismissal ~~annulled the verdict,~~ and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of ~~the~~a new preliminary hearing ~~dated 27~~in July 2016, the ~~judge~~Judge ordered the trial for all defendants, including ~~Eni.~~Eni SpA. At a hearing in February, 2018, the Public Prosecutor, concluding his indictment, requested — among other things — the imposition on Eni SpA of a pecuniary sanction. In September 2018, the Court of Milan rejected in part the charges of the Public Prosecutor and issued an acquittal verdict for Eni, for the former CEO and for the Company’s Chief Upstream Officer in relation to all charges. The ~~judgment~~former CFO of Eni was also acquitted of charges relating to Eni’s involvement. In December 2018 the court filed a written opinion setting forth the basis for its rulings. The Public Prosecutor and the parties who were convicted in the first ~~instance is pending.~~trial have appealed under the terms of the law. 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, declaring the appeal proposed by the Public Prosecutor inadmissible against the Company.

~~At the end of~~In 2012, Eni contacted the U.S. ~~Authorities — the DoJ~~Department of Justice (DoJ) and the U.S. SEC — in order to ~~voluntary~~voluntarily inform them about this matter, and has kept them informed about the developments in the Italian ~~prosecutors’ investigations.~~Prosecutors’ investigations and proceedings. Following Eni’s notification, ~~in 2012,~~ both the U.S. SEC and the DoJ ~~have~~ 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 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 the SEC about a potential resolution of the SEC’s investigation.

(iii) ~~Iraq~~Block OPL 245 — ~~Kazakhstan.~~Nigeria. A criminal ~~proceeding~~case is pending before the ~~Public Prosecutor~~Court of Milan ~~in relation to alleged crimes of~~alleging international corruption involving Eni’s activities in Kazakhstan regarding the management of the Karachaganak plant and the Kashagan project, as well as handling of assignment procedures of work contracts by Agip KCO. The Company has filed the documents collected and is fully collaborating with the Public Prosecutor. A number of managers and a former manager are involved in the investigation. The above-mentioned proceeding has been combined with another (the so-called “Iraq proceeding”) regarding a parallel proceeding related to Eni’s activities in Iraq, disclosed in the following paragraphs. On June 21, 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were searched by the Judicial Authorities. The search involved the offices of certain Group employees and of certain third parties in connection with ~~alleged crimes of conspiracy and corruption as part~~the acquisition in 2011 of the “Jurassic” project in Kuwait. Particularly, the alleged crimes would have been committed in order to illicitly influence the award of a construction contract outside Italy where Eni was the commissioning entity. Considering the claims of the Public Prosecutor, Eni and Saipem believed that they were damaged by the crimes committed by their employees. Eni considered those employees to have breached the Company’s Code of Ethics. In spite of this, Eni SpA and Saipem SpA were notified of being under investigation pursuant to the Legislative Decree No. 231/2001, which establishes the liability of entities for the crimes committed by their employees. Eni SpA was notified by the Public Prosecutor of a request of extension of the preliminary investigations that has led up to the involvement of another employee, as well as other suppliers in the proceeding. The Public Prosecutor of Milan requested Eni SpA to be debarred for one year and six months from performing any industrial activities involving the production sharing contract of 1997 with the Republic of Kazakhstan and in the subsequent administrative or commercial arrangements, or the prosecution of the mentioned activities under the supervision of a commissioner pursuant to Article 15 of the Legislative Decree No. 231 of 2001. On July 16, 2013, the Judge for Preliminary Investigation rejected the request for precautionary measures requested by the Public Prosecutor of Milan, because it considered the request groundless. The Public Prosecutor promptly appealed the decision before a higher degree court. After the appeal hearing, on October 21, 2013 such court rejected the appeal filed by the Public Prosecutor. The Re-examination Court rejected the appeal with judgment upon the merits due to the lack of serious evidence against Eni, accepting the defense arguments for which Eni suffered severe damages because of poor performances of some suppliers involved in the Kashagan project. In addition, the Court declared the lack of precautionary requirements considering the reorganization of the activities in Kazakhstan and taking into account of the initiatives of internal audit and control promptly adopted by Eni. The Public Prosecutor’s office did not appeal against the sentence of the Re-examination Court. Also based on this

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decision, on March 13, 2014, the Eni legal team requested to the Public Prosecutor to dismiss the proceeding. The Prosecutor’s Office filed a request for dismissal of all the natural persons, and, on 5 January 2017, the judge for preliminary investigations who issued the relevant decree granted the above-mentioned filing request. A similar measure is expected for Eni that was involved at the same proceeding pursuant to Legislative Decree no. 231/01.

~~(iv) Block~~ OPL 245 —exploration block in Nigeria. On In July 2, 2014, the ~~Italian~~ Public Prosecutor of Milan served Eni with a notice of investigation ~~relating to potential liability on the part of Eni arising from alleged international corruption,~~ pursuant to Italian Legislative Decree No. 231/2001 whereby companies are liable for the crimes committed by their employees when performing their tasks. As part of the proceeding, Eni was also subpoenaed for documents and other evidence. According to the subpoena, the01. The proceeding was commenced following a claim filed by NGO ReCommon ~~NGO~~ relating to alleged corruptive practices ~~that~~which, according to the Public Prosecutor, ~~would have~~ allegedly involved the Resolution Agreement made on April 29, 2011 relating to the so-called Oil Prospecting ~~license~~License of the offshore oilfield that was discovered in ~~Block 245 in Nigeria.~~OPL 245. Eni is fully ~~cooperating~~cooperated with the Public Prosecutor and ~~has~~ promptly filed the requested documentation. Furthermore, Eni ~~has~~ voluntarily reported the matter to the U.S. Department of Justice and the U.S. SEC. In July 2014, ~~the~~ 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 USU.S. lawyers concluded ~~in summary~~ that they detected no evidence of wrongdoing onby Eni ~~side were detected~~ in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. ~~The outcome of this review was transmitted to the judicial authorities. On~~In September ~~10,~~ 2014, the Public Prosecutor ~~of Milan~~ notified Eni of a restraining order issued by a British judge who ~~ruled~~ordered the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the ~~Italian~~ Public Prosecutor. ~~The order was~~Since the act had also been notified to ~~certain individuals,~~some persons, including ~~Eni’s~~the CEO of Eni and the former Chief Development, ~~Operations~~Operation & Technology Officer of Eni and ~~Technological Officer, as well as Eni’s~~the former ~~CEO. From the available documents,~~CEO of Eni, it was ~~inferred~~assumed that ~~such Eni’s officers and former officers are under investigation by~~ the ~~Italian Public Prosecutor.~~same had been registered in the register of suspects at the Milan Prosecutor’s office. During a hearing before a ~~Court of~~court in London onin September ~~15,~~ 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. OnIn December 22 2016, the Public Prosecutor of Milan notified Eni ~~was notified~~ of the conclusion of the preliminary investigation ~~by the Italian Judicial Authorities. Following the request of the Public Prosecutor of Milan that the~~and requested Eni’s CEO, ~~and~~ 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 ~~would stand trial, as well as~~and Eni ~~based on~~SpA, pursuant to Italian ~~law~~Legislative Decree No. 231/~~2001 on corporate entity responsibility, on February 14, 2017, Eni’s attorneys were notified of~~01. Upon the ~~schedule of the preliminary hearing due on April 20, 2017. Upon~~ notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor, ~~of Milan,~~ the independent US-based law firm was requested ~~by Eni~~ to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the ~~law firm~~ prior review. The USU.S. law firm was also provided with the documentation filed in the ~~Nigeria~~Nigerian proceeding mentioned below. The independent U.S. law firm concluded that the reappraisal of the matter in light of the new ~~documentations~~documentation available did not alter the outcome of the prior review. OnIn 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 and is currently ongoing.

In a separate criminal proceeding, two defendants, neither of whom is a current or former employee of the Company, chose to have their liability determined by 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 ~~27,~~ 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 ~~sitting in Abuja,~~ upon request from the Nigerian Economic and Financial ~~Crime~~Crimes Commission (EFCC), attaching OPL 245 temporarily ~~the property known as Oil Prospecting License 245 (“OPL 245”)~~ pending ~~the~~a proceeding ~~for~~in Nigeria relating to alleged corruption and money ~~laundering started in Nigeria. NAE made an~~laundering. After making this application, ~~to discharge the Order (along with the Shell affiliate co-holder of the license). On March 17, 2017, the Nigerian Court discharged the Order. Recently,~~ Eni became aware of a formal filing of charges by the ~~EFCC.~~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 ~~has provided~~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 ~~copy of charges filed by~~civil claim before an English court to obtain compensation for damages allegedly deriving from the ~~EFCC, to the US-based law firm engaged to review the OPL 245~~ transaction ~~who upon review of such documents, did not modify their conclusion according to which no evidence of wrongdoing on Eni side was detected~~that resulted in ~~relation to the acquisition~~assignment of the OPL 245 ~~license from~~to NAE and Shell subsidiary SNEPCO (Shell subsidiary). On April 15, 2019 the Nigerian ~~government.~~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 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.

~~(v)~~(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 ~~Refining~~with a further request for documentation and notified an Eni employee, who was the then Chief Development, Operation & ~~Marketing Division~~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 ~~(Criminal proceeding N. 6159/10 RGNR the Italian Public Prosecutor in Frosinone and~~. A criminal proceeding ~~No. 7320/14 RGNR the Italian Public Prosecutor in Rome).~~ ~~Two criminal proceedings are~~is currently pending, relating to alleged evasion of excise taxes in the context of ~~the~~ retail sales atin 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. ~~The~~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 ~~against~~involved a ~~third~~ company (Turrizziani Petroli) purchaser of Eni’s ~~fuel, is still pending in the phase of the preliminary investigation.~~fuel. This investigation was subsequently extended to Eni. The Company ~~has~~fully cooperated ~~fully with the~~

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~~proceeding~~ and provided all data and information concerning ~~the performance of~~ the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. ~~Eni ensured the best possible collaboration, handing in all the required documentation.~~ Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. ~~After the ending of the investigation, the Fiscal Police from Frosinone, along with the local Customs Agency, in November 2013 issued~~On June 24, 2019, a ~~claim related to the evasion of the payment of excise taxes in the 2007 2012 periods for €1.55 million. In May 2014,~~settlement agreement was signed between Eni and the Customs Agency, involving the determination of ~~Rome issued a payment notice relating~~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 ~~abovementioned claim that was filed~~Tax Commission. (ii) A second proceeding, concerning an investigation by the ~~Fiscal Police and Customs Agency~~Public Prosecutor’s Office of ~~Frosinone. The Company immediately appealed~~Prato, commenced in regard to the ~~Tributary Commission. The second~~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, ~~regarded~~concerns alleged ~~evasion~~missing payment of excise tax ~~payment~~ 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 ~~with~~presenting, however, some differences with regard to ~~both~~ the nature of the alleged crimes and the ~~responsibility subjected to verification. In fact, the~~responsibility.

The Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at ~~the~~ habitual ~~subtraction~~abduction of oil products at all of the 22 storage sites which are operated by Eni ~~over the national territory.~~in Italy. Eni is cooperating with ~~prosecutor~~the Prosecutor in order to defend the correctness of its operation. OnIn September ~~30,~~ 2014, a

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search was conducted at the office of the former chief ~~operating officer~~ of ~~Eni’s Refining & Marketing~~the R&M Division ~~as ordered by the Rome’s Public Prosecutor.~~in Rome. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also ~~relates~~relate to a period of time when hethe officer was in charge ~~of that~~at Eni’s R&M Division. OnIn March 5, 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. The three criminal proceedings were united together at Public Prosecutor’s Office of Rome, which is still conducting preliminary investigations. Ultimately, the Customs Agency, in reply to a request of the national association of refiners solicited by Eni, published a dedicated Circular which provides the rules the operators in the sector should follow to determine the quantity of oil products subjected to the excise tax, so as to give clarification to regional customs agencies, the Revenue Agency and the Finance Police. According to this Circular, Eni and other oil companies followed the correct procedures in order to determine the quantity subjected to the excise tax. 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 toat the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. ~~On this occasion, it became clear that the~~The proceeding ~~has been~~was then extended to a large number of employees and former employees of the ~~company. The~~Company. Eni has continued to provide full cooperation to the authorities.

During the course of 2018, as part of the general proceeding ~~is at~~no. 7320/2014, the Public Prosecutor of Rome notified the conclusion of the preliminary ~~investigations.~~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.

~~(vi) Block Marine XII, Congo.~~ ~~On July 9, 2015,~~In September 2018, Eni received, ~~from~~as injured party, the ~~U.S. Department~~notification of ~~Justice~~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 ~~subpoena ordering~~separated proceeding (No. 22066/17 RGNR), for which, in May 2017, the ~~Company to produce documents in view~~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 ~~employee,~~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 ~~assets “Marine XII” in Congo and relationships~~matter with ~~certain persons and companies. According~~respect to ~~preliminary informal contacts between Eni’s U.S. lawyers and~~ the Authority, this hearing is part of a broader investigation, which is currently being carried out with regard to third parties. Within such investigation, Eni is considered a witness and — potentially — a damaged party. The documents required by the Authority are currently being collected and filed with the Authority.

~~4. Tax Proceedings~~

~~Italy~~

~~(i) Eni SpA — municipal tax related to certain oil platforms located in the Italian territorial waters.~~ Several tax proceedings are pending in Italy, as certain municipalities claimed Eni SpA omitted payments of a tax on property relating oil platforms located in the territorial waters under the municipality administration. After completing all degrees of judgment before Italian tax courts, on February 24, 2016, the Third Instance Court sentenced that: i) property taxes on platforms are due by Eni; ii) the taxable basis is to be defined by considering the platforms carrying amounts, insteadevents of the ~~replacement cost; iii) sanctions are not applicable. The~~aforementioned proceeding, continued with an indictment before a trial judge to determine the due amount. In a similar proceeding relating to another oil company, the Third Instance Court confirmed that these industrial installations might be subject to this local tax. Based on the outcomes

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~~of these resolutions, Eni started an out of court procedure to reach~~including a ~~settlement on the matter with the local authorities who~~forensic review. The final report, submitted claims against the Company based on the taxability of oil platforms. This settlement will be pursued on condition that the local authorities agree with Eni a fair tax base and renounce any claim of sanctions as established by the Third Instance Court which resolved the inapplicability of any sanction to the ~~matter in~~Control and Risk Committee, the ~~case involving a local municipality. Based~~Watch Structure and the Board of Statutory Auditors on September 12, 2018, concluded that following the ~~expectation of management~~review carried out with respect to ~~successfully conclude these settlements, Eni accrued a tax provision.~~

~~(ii) Eni SpA — Excise taxes.~~ ~~On May 31, 2016~~ the Customs Agency issued to Eni a payment notice for a total sum of €134 million (of which €114 million referring to excise taxes and €20 million referring to interests), in addition to fines amounting to €34 million. This followed a claim filed in 2011, referring to legal proceeding startedallegations made by the Court of Milan in 2010 pertaining to alleged culpable omission to pay excise taxes (for the period 2003 – 2008) due on 9.8 billion cubic meters of natural gas marketed by Eni in Italy. With a sentence dated June 28, 2012 the Public Prosecutor of Milan, there was not sufficient factual evidence to prove the ~~Tribunal resolved~~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 ~~dismiss~~provide independent legal advice in relation to the ~~proceeding against all defendants because the fact~~facts under investigation. Their report, dated November 22, 2018, did not ~~constitute an offence. In addition,~~find facts which could suggest any involvement of any Eni employees in the ~~appeal filed~~crimes alleged by the Public ~~Prosecutor~~Prosecutor. On June 4, 2018, Consob, the Italian market regulator, requested to be informed about the above mentioned proceeding. The request was ~~rejected by a final-degree Court with sentence dated July 3, 2013 and filed on January 7, 2014. With regard~~addressed to the ~~administrative proceeding, considering the documentation filed by Eni in the aftermath, the volumes allegedly subtracted~~Company and to ~~tax payment were reduced to 650 million cubic meters. Thus, the corresponding amount~~its Board of allegedly due excise taxes decreased from €1.7 billion, initially claimed by the Public Prosecutor, to €114 million. Like the initial claim, the residual claim appears to be groundless, taking into account the fact that the gas volumes input into the national grid by Eni and gas volumes off-taken at each delivery pointsStatutory Auditors.

Specifically, Consob asked for reselling to final customers have different calorific power. This was confirmed by the opinion of sector experts and acknowledged by the Customs Agency itself during the consultation process with the Italian association of gas resellers. Therefore, the Customs Agency issued a new administrative claim configuring erroneous compilation of the consumption declaration only. The Customs Agency reiterated the claim because — even if the incidence of the calorific value has been acknowledged from a technical and scientific point of view and shared by the Agency itself, — at the same time the matter has not been explicitly regulated by an administrative act. In order to safeguard the Company’s assets, Eni’s management commenced the following initiatives: (i) an administrative claim has been filed in order to suspend the tax collection, accepted by the Customs Agency; (ii) an appeal against the Agency’s claim before a Tax Judge has been filed whose discussion hearing is scheduled. Based on current information and taking into account the outcome of the ~~criminal litigation, the objections presented are considered groundless and, therefore, the Company did not accrue any tax provision in the consolidated financial statements 2016.~~

~~Outside Italy~~

~~(iii) Eni Angola Production BV.~~ The tax Authorities of Angola filed a notice of tax assessment in which it claimed the improper deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as partner of the Cabinda concession. The company paid the higher taxes under contestation for the years 2002 – 2006, requiring the recognition of its position for subsequent years and, accordingly, filed an appeal against this decision. The judgment is still pending before the Supreme Court. The tax authorities also contested to Eni Angola Production BVforensic review and to ~~Eni Angola Exploration BV the recovery of certain costs (cost oil) for the tax years from 2003 to 2009,~~be updated about any other audit action taken in relation to ~~licenses regulated~~the matter by ~~oil contracts in Production Sharing Agreements,~~the Company and ~~that would result in~~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 ~~payment of further taxes on the higher profit oil resulting~~request from the ~~lack~~Prosecutor Office to transmit certain documentation in accordance with the Italian Code of Criminal Procedure. The request targeted evidence and documents relating to the ~~recognition of such costs. The companies contested the legitimacy of the claim formulated~~internal audit performed by the ~~Ministry of Finance either as~~Company and any possible external review concerning certain tasks that had been assigned to the power to approve the cost oil (recoverable costs) and the shares of profit oil contract lies solely to Sonangol (first party in the oil contract), or the tax deductibility of such costs. The companies have presented an appeal that is waiting to be discussed. Eni accrued a tax provisionformer 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.

~~5. Settled proceedings~~

~~(i) Action commenced~~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 ~~Municipality of Carrara for the remediation and reestablishment of previous environmental conditions at the Avenza site and payment of environmental damage.~~ ~~In relation~~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, ~~brought by~~ the ~~Municipality of Carrara~~internal audit reports and the ~~Ministry for the Environment against Syndial SpA for the compensation of alleged environmental damages at the Avenza site. The proceeding was closed without ascertaining any responsibility~~reports of the ~~company.~~ 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 ~~particular~~November 2019, Eni received a notice to extend the ~~Minister indicated Syndial~~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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~~responsible~~(iii) Eni SpA — Public Prosecutor of Milan — Insider trading. In March 2019, a request for ~~environmental damages on~~extending certain investigations was notified to Eni’s Chief Upstream Officer by the ~~belief that: a) Syndial~~public prosecutor office of Milan. The commencement of those investigation was ~~liable~~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 environmental damage as the Eni subsidiary took over the site from the previous owners assuming all existing liabilities; b) it was responsible for managing the plant and inadequately remediating the site after the occurrence of an incident in 1984; c) it was responsible for omitted clean-up. Syndial established itself as defendant. remaining pending litigations.

The Third Instance Court ~~sentenced that only~~ruling applied to the ~~first motivation~~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 ~~appeal filed~~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 ~~Ministry is valid, which related~~municipality for a total tax of €19 million, in addition to the ~~statute of limitations for~~penalties applicable by law.

Based on the ~~crime of disaster applicable exclusively to the previous owners~~resolution of the ~~site. Therefore,~~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 ~~has definitely confirmed that Syndial is not liable, neither~~of Rome, to seek a compensation for ~~activities directly conducted (including~~ alleged ~~delay/omission~~damages caused by alleged anti-competitive behavior on part of the ~~clean-up activities claimed by the Ministry) nor for strict liability (as it took over the site from the previous owners). Particular attention should be paid to this second profile~~three petroleum companies in the ~~light~~supply of ~~the fact that the Avenza site was transferred to Eni due to a law provision.~~

~~(ii) Eni SpA — Investigation for alleged violations of the Consumer Code~~jet fuel in the ~~matter of billing of gas and power consumptions.~~ ~~In relation to the proceeding brought~~years 1998 through 2009. The claim was based on a decision rendered by the Italian Antitrust Authority ~~(AGCM)~~ in regard of alleged unfair commercial practices under the Consumer Code in the billing of gas and power consumptions to retail customers, after the conclusion of the investigation, the AGCM notified Eni its final ruling by imposing to the company a sanction of €3.6 million.June 2006. The ~~sanction has been paid. Eni appealed the~~antitrust decision ~~to the Regional Administrative Court.~~

~~(iii) Fatal accident Truck Center Molfetta — Prosecuting body: Public Prosecutor of Trani.~~ In relation to a fatal accident occurred in March 2008 that caused the death of four workers deputed to the cleaning of a tank car used for the transportation of liquid sulphur produced by Eni in the Refinery of Taranto, the Public Prosecutor of Trani accused Eni and ~~eight employees~~another five petroleum companies of anti-competitive agreements designed to split the ~~company~~market for ~~alleged manslaughter, grievous bodily harm~~jet fuel supplies and ~~illegal disposal~~blocking the entrance of ~~waste materials. The decision of a first instance court which ruled acquittal for~~new players in the years 1998 through 2006. In June 2019 the lawsuit was settled between all the ~~defendants and for~~involved parties. The amount transacted by Eni ~~SpA, as legal entity, with the wide formula “because the alleged fact does not exist”~~ was ~~upheld~~previously accrued in the ~~subsequent degrees of judgments and became final on July 27, 2016.~~financial statements.

~~(iv)~~(ii) Eni SpA — ~~Reorganization procedure~~Public Prosecutor’s Office of Rome — Criminal Procedure No. 2711/2019 — VAT returns. On September 16, 2019, a notice of extension of the ~~airlines companies Volare Group, Volare Airlines~~preliminary investigations was notified to the former CEO and ~~Air Europe — Prosecuting body: Delegated Commissioner.~~ Inthe current CEO of Eni, in relation to the ~~bankruptcy clawback~~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 ~~reorganization procedure filed~~price charged by GasTerra to Eni for the ~~airlines companies Volare Group, Volare Airlines~~gas supplied in the 2012 – 2015 period. On that occasion, Eni and ~~Air Europe~~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 ~~request of override of all the payments made by those entities to~~contractual price. Eni, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, the Court of Appeal of Milan ruled Eni to return a total amount of €9 million. The plaintiffs requested that the sentence against Eni would be reassessed to an amount of about €18 million. The proceeding is pending before a third-degree court. Eni accrued a provision in respect to this proceeding. The proceeding is no longer significant.

~~(v) Investigation by the Italian Antitrust about Eni’s determination of Italian market share of the Italian gas wholesale market.~~ With Resolution No. 25064 of August 1, 2014, the Italian Antitrust commenced an investigation to verify whether Eni controlled a bigger share of the domestic wholesale gas market than it had declared. Following the Legislative Decree No. 130 of 2010, which envisages a 55% ceiling to the wholesale market share for each Italian gas operator who inputs gas into the Italian backbone network, Eni declared that its market share was equal to 54%, therefore slightly below the established threshold. Eni calculated its market share by excluding certain sales of gas volumes. On the other hand, the Antitrust rejected this calculation method and therefore concluded that Eni’s market share was actually 56%. Nonetheless, the Antitrust decided not to impose any finerelying also on ~~the Company as the violation was immaterial. The Antitrust considered the fact that in its declaration Eni explained clearly how its market share was calculated. Besides that, in~~ 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 ~~Ministry~~provisional seizure of ~~Economic Development, expressed during~~Eni’s investment in its subsidiary Eni International BV for the ~~investigation,~~alleged receivable due by Eni ~~calculated~~(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 ~~market share correctly. Eni filed an appeal against the Antitrust’s decision before the Regional Administrative Court~~rights of ~~Lazio, asking for annulment. Management does not expect any liability in connection with this proceeding.~~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,

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in some legal contexts, private owners. Pursuant to the assignment of mineral ~~concession,~~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 concessions, Eni pays royalties and taxes in accordance with local tax legislation. 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 of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties based on ~~the basis of~~ 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

~~Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the “Financial Review”, paragraph “Risk factors and uncertainties”.~~ 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 ~~No.~~ 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 to emission trading a lower assignment of emission permits respect 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 ~~2016,~~2019, 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 ~~20.22~~19.30 million tonnes, Eni was awarded free emission allowances of ~~7.06~~7.73 million tonnes, determining a deficit of ~~13.16~~11.57 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market.

3928 Revenues and other income

~~Net sales~~Sales from operations

(€ million) 2014 2015 2016
Revenues from sales and services 98,256 72,290 55,764
Change in contract work in progress (38) (4) (2)
98,218 72,286 55,762


(€ million)	Exploration & Production		Gas & Power		Refining & Marketing and Chemical		Corporate and Other activities		Total
2019
Sales from operations		10,499		38,160		21,017		205		69,881
Products sales and service revenues
Sales of crude oil		3,505		17,334		27				20,866
Sales of oil products		1,189		3,000		16,615				20,804
Sales of natural gas and LNG		5,454		12,468						17,922
Sales of petrochemical products				316		3,772		22		4,110
Sales of other products		68		2,502		16		7		2,593
Services		283		2,540		587		176		3,586
Total		10,499		38,160		21,017		205		69,881
Transfer of goods/services
Goods/Services transferred in a specific moment		9,946		38,047		20,768		87		68,848
Goods/Services transferred over a period of time		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

~~Revenues from sales were stated net of the following items:~~

(€ million) 2014 2015 2016
Excise taxes 12,289 11,889 11,913
Exchanges of oil sales (excluding excise taxes) 1,586 1,154 878
Services recharged to joint venture partners 5,191 5,609 4,441
Sales to service station managers for sales billed to holders of credit cards 1,804 1,643 1,553
20,870 20,295 18,785

~~Net sales~~Sales from operations by industry segment and geographical area of destination are disclosed in note 4635 — ~~Information~~Segment information and information by ~~industry segment and by geographical~~geographic area.

~~Net sales~~Sales from operations with related parties are disclosed in note 4736 — Transactions with related parties.

Other income and revenues

(€ million) 2014 2015 2016
Gains on price adjustments under overlifting/underlifting transactions 390 253 238
Compensation for damages 43 36 122
Lease and rental income 92 85 81
Contract penalties and other trade revenues 37 36 72
Gains from sale of assets 84 457 14
Other proceeds(*)
433 385 404
1,079 1,252 931


(€ 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 ~~included herein was lower than €50 million.~~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).

~~Compensations of €122~~Other proceeds include €368 million related to ~~a loss in property value following an accident occurred at~~ the ~~EST conversion plant at the Sannazzaro refinery, which resulted in a write-off~~recovery of the ~~damaged units for €193 million and the recognition~~cost share of ~~a provision for removal and cleanup~~right-of-use assets pertaining to partners of ~~€24 million. The portion of losses not covered by the insurance compensation (€95 million) corresponds to the risk retained~~non-incorporated joint operations operated by Eni.

Other income and revenues with related parties are disclosed in note 4736 — Transactions with related parties.

~~40 Operating expenses~~29 Costs

Purchase, services and other charges

(€ million) 2014 2015 2016
Production costs - raw, ancillary and consumable materials and goods 60,987 39,812 27,783
Production costs - services 12,414 13,197 12,727
Operating leases and other 2,655 2,205 1,672
Net provisions for contingencies 340 644 505
Expenses for price variation on overliftling and underlifting operations 409 278 240
Other expenses 918 1,135 1,512
77,723 57,271 44,439
less:
- capitalized direct costs associated with self-constructed assets -
tangible assets (238) (323) (297)
- capitalized direct costs associated with self-constructed assets -
intangible assets (81) (100) (18)
77,404 56,848 44,124


(€ million)	2019		2018		2017
Production costs - raw, ancillary and consumable materials and goods		36,272		41,125		35,907
Production costs - services		11,589		10,625		12,228
Lease expense and other		1,478		1,820		1,684
Net provisions for contingencies		858		1,120		886
Charges for price variation on overliftling and underlifting operations						145
Other expenses		879		1,130		931
		51,076		55,820		51,781
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(197)		(192)		(224)
- capitalized direct costs associated with self-constructed assets - intangible assets		(5)		(6)		(9)
		50,874		55,622		51,548

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~~Service costs~~Purchase, services and other charges include geological and geophysical ~~expenses related to the~~costs of exploration activities ~~of the Exploration & Production segment amounting to €204~~for €275 million (€~~368~~287 million and ~~€254~~€273 million in ~~2014~~2018 and ~~2015,~~2017, respectively). In 2018 and 2017, the item included operating leases for €872 million and €1,022 million, respectively.

Costs incurred in connection with research and development ~~activity recognized in~~activities expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to ~~€161~~€194 million (€~~174~~197 million and ~~€176~~€185 million in ~~2014~~2018 and ~~2015,~~2017, respectively).

~~Operating leases and other comprised operating leases for €566 million (€559 million and €635 million in 2014 and 2015, respectively) and royalties~~Royalties on the extraction of hydrocarbons ~~for €572~~amounted to €1,183 million (€~~1,278~~1,043 million and ~~€865~~€674 million in ~~2014~~2018 and ~~2015,~~2017, respectively).

~~Other expenses of €1,512 million (€918 million and €1,135 million in 2014 and 2015, respectively) included provisions~~Additions to ~~the reserve of allowance for doubtful accounts of trade receivables of the Gas & Power segment, primarily in the retail business, for €399 million (€549 million in 2015).~~

~~Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below:~~

(€ million) 2014 2015 2016
To be paid:
- within 1 year 522 495 593
- between 2 and 5 years 1,114 1,061 1,040
- beyond 5 years 726 809 785
2,362 2,365 2,418

Operating leases primarily regarded drilling rigs, time charter and long-term rentals of vessels, land, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases that may limit the ability of Eni to pay dividends, use assets or take on new borrowing.

~~Risk~~ provisions net of reversal of unused provisions ~~amounted to €505 million (€340 million and €644 million in 2014 and 2015, respectively) and~~ mainly related to net addition for litigations amounting to €60 million (net provisions of €101 million and €375 million in 2018 and 2017, respectively) and net additions for environmental liabilities amounting to ~~€198~~€329 million (net provisions of ~~€177~~€266 million and ~~€232~~€200 million in ~~2014~~2018 and ~~2015, respectively) and net provisions for litigations amounting to €55 million (net provisions of €35 million and €179 in 2014 and 2015,~~2017, respectively). More information is provided in note 3020 — ~~Provisions for contingencies. Risk~~Provisions. Net additions to provisions ~~net of reversal of unused provisions~~by segment are disclosed in note 4635 — Segment information and information by geographic area.

Information ~~by industry segment~~about leases is disclosed in note 12 — Right-of-use assets and ~~by geographical area.~~lease liabilities.

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Payroll and related costs


(€ million)	2014		2015		2016		2019		2018		2017
Wages and salaries		2,590		2,648		2,491		2,417		2,409		2,447
Social security contributions		445		453		445		449		448		441
Cost related to employee benefit plans		73		85		81		85		220		113
Other costs		160		182		202		213		170		162
		3,268		3,368		3,219		3,164		3,247		3,163
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(278)		(203)		(215)		(152)		(142)		(202)
- capitalized direct costs associated with self-constructed assets - intangible assets		(61)		(46)		(10)		(16)		(12)		(10)
		2,929		3,119		2,994		2,996		3,093		2,951

Other costs ~~of €202 million (€160 million and €182 million in 2014 and 2015, respectively)~~ comprised provisions for redundancy incentives of ~~€47~~€45 million (€537 million and ~~€31~~€18 million in ~~2014~~2018 and ~~2015,~~2017, respectively) and costs for defined contribution plans of ~~€83~~€99 million (€8595 million and ~~€86~~€90 million in ~~2014~~2018 and ~~2015,~~2017, respectively).

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Cost related to employee benefit plans are described in note 3121 — 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:

2014 2015 2016
(number) Subsidiaries Joint operations Subsidiaries Joint operations Subsidiaries Joint operations
Senior managers 1,049 25 1,044 17 1,018 18
Junior managers 8,912 121 9,091 108 9,160 109
Employees 18,143 595 17,685 379 17,180 384
Workers 6,358 559 5,895 303 5,703 294
34,462 1,300 33,715 807 33,061 805

~~The above Group average number do not include employees of discontinued operations (Saipem Group).~~


(number)	2019				2018				2017
(number)	Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations
Senior managers		1,014		16		999		17		995		17
Junior managers		9,267		77		9,095		84		9,089		98
Employees		15,945		361		16,220		361		16,721		371
Workers		4,910		287		5,259		283		5,659		285
		31,136		741		31,573		745		32,464		771

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 ~~and operating~~ 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, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017 – 2019 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.

The Long-Term Monetary Incentive Plan 2017-2019 provides for three annual awards for the years 2017, 2018 and 2019 and is 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 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 within the category of employee compensation, in accordance with IFRS, the cost of the plan is determined based on the fair value of the financial instruments awarded to the beneficiaries and the number of shares that will be granted at the end of the vesting period; the cost is accruing along the vesting period.

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The number of shares that will be granted at the end of the vesting period is conditioned on a 50-50 basis to actual results of two performance parameters against preset targets: (i) a 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 Group”)37 and the TSR of their corresponding stock exchange market38; (ii) growth in the Net Present Value (NPV) of proved reserves benchmarked against the Peer Group. 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 in 2019, 1,517,975 in 2018 and 1,719,061 in 2017; the weighted average fair value of the shares at the same date was €9.88 per share in 2019, €11.73 per share in 2018 and €7.99 per share in 2017.

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), taking into account the fair value of the Eni share at the grant date (€13.714 per share in 2019; €14.246 per share in 2018; €13.81 per share in 2017), reduced by dividends expected along the vesting period (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), the volatility of the stock (19% for attribution 2019; 20% for attribution 2018; 25% for attribution 2017), 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, the costs related to the long-term monetary incentive plan 2017 – 2019, recognized as a component of the payroll cost, amounted to €9 million (€5 million in 2018; €0.4 million in 2017) 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 ~~(including contributions and ancillary costs) amounted to €43 million, €42 million and €44 million for 2014, 2015 and 2016, respectively, and~~ consisted of the following:


(€ million)	2014		2015		2016		2019		2018		2017
Wages and salaries		25		26		26		28		27		25
Post-employment benefits		2		2		2		2		2		2
Other long-term benefits		10		12		12		12		10		9
Indemnities upon termination of employment		6		2		4		12				7
		43		42		44		54		39		43

Compensation of Directors and Statutory Auditors

Compensation of Directors amounted to ~~€10.1~~€9.2 million, ~~€6.7~~€9.6 million and ~~€7.1~~€14.5 million for ~~2014, 2015~~2019, 2018 and ~~2016,~~2017, respectively. Compensation of Statutory Auditors amounted to ~~€0.419~~€0.613 million, ~~€0.551~~€0.604 million and ~~€0.738~~€0.760 million in ~~2014, 2015~~2019, 2018 and ~~2016,~~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.

~~Other operating income (loss)~~

The ~~analysis of net income (loss) on commodity derivatives was as follows:~~

(€ million) 2014 2015 2016
Net income (loss) on cash flow hedging derivatives (133) 2 (1)
Net income (loss) on other derivatives 278 (487) 17
145 (485) 16

~~Net income (loss) on cash flow hedging derivatives related to the ineffective portion~~group consists of the ~~hedging relationship on commodity derivatives was recognized through profit~~following oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and ~~loss~~Total.

The performance condition connected with the TSR in accordance with the ~~Gas & Power segment.~~international accounting standards represents a so-called market condition.

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Net income (loss) on other derivatives included: (i) 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 amounting to a net income of €36 million (net income of €247 million in 2014 and net loss of €471 million in 2015); and (ii) the fair value valuation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts of the Exploration & Production segment amounting to a net loss of €19 million (net income of €31 million in 2014 and net loss of €16 million in 2015).

~~Operating expenses with related parties are reported in note 47 — Transactions with related parties.~~

~~Depreciation and amortization~~

(€ million) 2014 2015 2016
Depreciation, depletion and amortization:
- tangible assets 7,356 8,646 7,308
- intangible assets 326 303 253
7,682 8,949 7,561
less:
- capitalized direct costs associated with self-constructed assets - tangible assets (6) (9) (2)
7,676 8,940 7,559

~~Depreciation and amortization by industry segment are disclosed in note 46 – Information by industry segment and by geographical area.~~

~~Net impairment (reversal)~~

(€ million) 2014 2015 2016
Impairments:
- tangible assets 1,196 5,993 1,067
- intangible assets 138 544
1,334 6,537 1,067
less:
- reversal of impairments - tangible assets (64) (3) (1,153)
- reversal of impairments - intangible assets (389)
1,270 6,534 (475)

~~Net impairment (reversal) by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.~~

~~Write-off~~

(€ million) 2014 2015 2016
Write-off
- tangible assets 936 678 289
- intangible assets 262 10 61
1,198 688 350

~~Write-off by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.~~

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4130 Finance income (expense)


(€ million)	2014		2015		2016		2019		2018		2017
Finance income (expense)
Finance income		5,701		8,635		5,850		3,087		3,967		3,924	��
Finance expense		(7,057)		(10,104)		(6,232)		(4,079)		(4,663)		(5,886)
Net finance income (expense) from financial assets held for trading		24		3		(21)		127		32		(111)
		(1,332)		(1,466)		(403)
Income (expense) from derivative financial instruments		165		160		(482)		(14)		(307)		837
		(1,167)		(1,306)		(885)		(879)		(971)		(1,236)

The ~~breakdown by lenders or type~~analysis of ~~net~~ finance income ~~or expense is provided below:~~(expense) was as follows:


(€ million)	2014		2015		2016		2019		2018		2017
Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(759)		(740)		(639)		(618)		(565)		(638)
Interest due to banks and other financial institutions		(112)		(98)		(118)
Interest and other income from financial receivables and securities held for non-operating purposes		26		2		37
Net finance income (expense) on financial assets held for trading								127		32		(111)
Interest and other expense due to banks and other financial institutions								(122)		(120)		(113)
Interest on lease liabilities								(378)
Interest from banks		19		19		15		21		18		12
Net finance income (expense) from financial assets held for trading		24		3		(21)
Interest and other income on financial receivables and securities held for non-operating purposes								8		8		16
		(802)		(814)		(726)		(962)		(627)		(834)
Exchange differences								250		341		(905)
Positive exchange differences		5,430		8,400		5,579
Negative exchange differences		(5,845)		(8,754)		(4,903)
		(415)		(354)		676
Income (expense) from derivative financial instruments								(14)		(307)		837
Other finance income (expense)
Interest and other income on financing receivables and securities held for operating purposes								112		132		128
Capitalized finance expense		163		166		106		93		52		73
Interest and other income on financing receivables and securities held for operating purposes		74		120		143
Finance expense due to the passage of time (accretion discount)(a)		(293)		(291)		(312)		(255)		(249)		(264)
Other finance (expense)		(59)		(293)		(290)
Other finance income (expense)								(103)		(313)		(271)
		(115)		(298)		(353)		(153)		(378)		(334)
		(1,332)		(1,466)		(403)		(879)		(971)		(1,236)

(a)

The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities.

~~Finance~~Information about leases is disclosed in note 12 — Right-of-use assets and lease liabilities.

The analysis of income ~~(loss) on~~(expense) from derivative financial instruments ~~consisted of the following:~~

(€ million) 2014 2015 2016
Options 68 33 24
Derivatives on exchange rate 51 96 (494)
Derivatives on interest rate 46 31 (12)
165 160 (482)

Net loss from derivatives of €482 million (net income of €165 million and €160 million in 2014 and 2015, respectively) was recognized in connection with 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. The lack of formal requirements to qualify these derivatives as

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hedges under IFRS also entailed the recognition in profit or loss of currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments.

Net income on options of €24 million (net income of €68 million and €33 million in 2014 and 2015, respectively) related to: (i) the reversal through profit and loss of the fair value reserve relating to the embedded options of the bond convertible into ordinary shares of Snam SpA amounting to an income of €26 million (income of €23 million and €33 million in 2014 and 2015, respectively); (ii) the fair value of the option embedded in non-dilutive equity-linked convertible bond for a net loss of €2 million. In 2014, the measurement at fair value of the options embedded in the bond convertible into ordinary shares of Galp Energia SGPS SA resulted in an income of €45 million. More information is ~~provided~~disclosed in note 2923 — ~~Long-term debt~~Derivative financial instruments and ~~current portion of long-term debt.~~hedge accounting.

~~More information finance income (expense) is provided~~Operating expenses with related parties are disclosed in note 4736 — Transactions with related parties.

4231 Income (expense) from investments

Share of profit (loss) of equity-accounted investments

(€ million) 2014 2015 2016
Share of profit from equity-accounted investments 188 150 77
Share of loss from equity-accounted investments (77) (615) (370)
Decreases (increases) in the provision for losses on investments from equity accounted investments (1) (6) (33)
110 (471) (326)

More information is provided in note ~~20 –~~15 — Investments.

Share of profit ~~(loss)~~or loss of equity accounted investments by industry segment is disclosed in note 4635 — ~~Information~~Segment information and information by ~~industry segment and by geographical~~geographic area.

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Other gain (loss) from investments


(€ million)	2014		2015		2016		2019		2018		2017
Dividends		385		402		143		247		231		205
Net gain (loss) on disposals		160		164		(14)		19	��	22		163
Other net income (expense)		(179)		10		(183)		15		910		(33)
		366		576		(54)		281		1,163		335

~~In 2016, dividend~~Dividend income ~~of €143 million essentially~~primarily related to Nigeria LNG Ltd for ~~€76~~€186 million and to Saudi European Petrochemical Co for ~~€45 million.~~€46 million (€187 million and €35 million in 2018 and €167 million and €21 million in 2017, respectively).

In ~~2015, dividend~~2018, other net income ~~of €402 million primarily related to Nigeria LNG Ltd for €222 million, Snam SpA for €72 million, Saudi European Petrochemical Co for €69 million and Galp Energia SGPS SA for €21 million.~~

In 2014, dividend income of €385 million related to the Nigeria LNG Ltd for €247 million, Saudi European Petrochemical Co for €57 million, Snam SpA for €43 million and Galp Energia SGPS SA for €22 million.

~~In 2016, net loss on disposals amounting to €14 million related to: (i) a loss of €32 million for the sale of 2.22% share capital (entire stake owned) of Snam SpA; (ii)~~included a gain of ~~€11~~€889 million ~~related to~~deriving from the ~~sale~~business combination between Eni Norge AS and Point Resources AS, with the establishment of ~~100% share capital of Eni Hungaria Zrt and Eni Slovenjia doo; and (iii) a gain of €6 million related to~~joint venture the

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~~sale of 30% share capital (entire stake owned) of Pokrovskoe Petroleum BV and~~ Vår Energi AS, determined by the ~~sale~~difference between the book value of the ~~60% share capital (entire stake owned) of Zagoryanska Petroleum BV.~~

~~In 2015, net gains on disposals amounting~~investment corresponding to ~~€164 million related to: (i) a gain of €98 million for~~ the sale of an 8% stake in Galp Energia SGPS SA; (ii) a gain of €46 million for the sale of a 6.03% stake in Snam SpA; (iii) a gain of €32 million for the sale of 100% stake in Ceská Republika Sro; (iv) a gain of €31 million for the sale of a 100% stake of Eni Romania Srl; (v) a gain of €6 million for the sale of 32.445% stake (entire stake owned) in Ceská Rafinérská AS (CRC); (vi) a gain of €1 million of 100% stake in Eni Slovensko Spol Sro; and (vii) a loss of €47 million for the sale of a 76% stake in Inversora de Gas Cuyana SA (entire stake owned), a 6.84% stake in Distribudora de Gas Cuyana SA (entire stake owned), a 25% stake in Inversora de Gas del Centro SA (entire stake owned) and a 31.35% stake in Distribudora de Gas del Centro SA (entire stake owned).

In 2014, net gains on disposals amounting to €160 million related to: (i) €96 million for the sale of a 8.15% of the share capital of Galp Energia SGPS SA, of which €77 million related to the reversal of the reserve for fair value measurement; (ii) €54 million for the sale of a 20% (entire stake owned) of the share capital of South Stream Transport BV to Gazprom; and (iii) €9 million for the sale of a 50% (entire stake owned) of the share capital of EnBW Eni Verwaltungsgesellschaft mbH to EnBW Energie Baden-Württemberg AG.

In 2016, other net losses of €183 million included: (i) an impairment for €162 million relating to Unión Fenosa Gas SA (€84 million), PetroSucre (€65 million) and Genomatica Inc (€13 million).

~~In 2015, other net income of €10 million included: (i) a gain on the remeasurement at market~~ fair value of ~~77.7 million shares of Snam SpA for €49 million to which~~ the ~~fair~~combined net assets and the book value option was applied as provided for by IAS 39; (ii) a reversal of unutilized provision for losses on investments of €10 million relating to Caspian Pipeline Consortium R — Closed Joint Stock Co; and (iii) an impairment for €49 million relating to Unión Fenosa Gas SA.

In 2014, other net expense of €179 million included the remeasurement at market fair value at the balance sheet date of 66.3 million shares of Galp Energia SGPS SA (loss for €231 million at the price of €8.43 per share) and of 288.7 million shares of Snam SpA (income for €10 million at the price of €4.1 per share). The valuation of the ~~shares of these investments was based on the fair value option as underlying two convertible bonds.~~net assets sold.

~~More information is provided in note 20 – Investments.~~

4332 Income taxes


(€ million)	2014		2015		2016		2019		2018		2017
Current taxes:
- Italian subsidiaries		(573)		155		195		347		301		712
- subsidiaries of the Exploration & Production segment - outside Italy		6,512		4,015		2,671		4,729		4,906		3,167
- other subsidiaries - outside Italy		116		218		133		152		163		142
		6,055		4,388		2,999		5,228		5,370		4,021
Net deferred taxes:
- Italian subsidiaries		369		881		(243)		599		130		(464)
- subsidiaries of the Exploration & Production segment - outside Italy		79		(2,156)		(813)		(172)		497		(162)
- other subsidiaries - outside Italy		(37)		9		(7)		(64)		(27)		72
		411		(1,266)		(1,063)		363		600		(554)
		6,466		3,122		1,936		5,591		5,970		3,467

Current income taxes payable by Italian subsidiaries ~~amounted~~referred to ~~€195 million and were in respect of the Italian corporate taxation (IRES for €12 million and IRAP for €7 million) and~~ foreign taxes ~~on the share of profit earned outside Italy~~ for ~~€176~~€137 million.

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The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of ~~27.5%~~24% (same amount in ~~2014~~2018 and ~~in 2015)~~2017) and the effective tax charge is the following:


(€ million)	2014		2015		2016		2019		2018		2017
Profit (loss) before taxation		8,274		(4,277)		892		5,746		10,107		6,844
Tax rate (IRES) (%)		27.5		27.5		27.5		24.0		24.0		24.0
Statutory corporation tax charge (credit) on profit or loss		2,275		(1,176)		245		1,379		2,426		1,643
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy		4,065		2,576		1,152		2,934		3,096		1,882
- impact pursuant to the write-off of deferred tax assets and recalculation of tax rates		1,002		1,514		397
- impact pursuant to the write-down of deferred tax assets and recalculation of tax rates								938		261		(96)
- tax effects related to previous years								147		(24)		(1)
- impact pursuant to foreign tax effects of italian entities								105		46		54
- effect due to the tax regime provided for intercompany dividends		51		114		87		65		47		1
- Italian regional income tax (IRAP)		5		100		42		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		25		(39)		8				(1)		(177)
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009		(825)
- effect due to discontinued operations		(97)		(288)
- other adjustments		(35)		321		5		(2)		69		23
		4,191		4,298		1,691		4,212		3,544		1,824
Effective tax charge		6,466		3,122		1,936		5,591		5,970		3,467

~~In 2016, the~~The higher tax charges at non-Italian subsidiaries ~~of €1,152 million~~ related to the Exploration & Production segment for ~~€1,211 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €397~~€2,934 million ~~was incurred at Italian subsidiaries and essentially related to a write-off at deferred tax assets due to projections of lower future taxable profit.~~

In 2015, the higher tax charges at non-Italian subsidiaries of €2,576 million related to the Exploration & Production segment for €2,410 million, including a write-off of deferred tax assets due to a reduced profitability outlook of €1,058 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,514 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit and to a reduction due to a change in the statutory tax rate from 27.5% to 24%, starting from January 1, 2017. The effect due to the Italian regional income tax (IRAP) of €100 million included a write-off at deferred tax assets due to projections of lower future taxable profit for €54 million.

In 2014, the higher tax charges at non-Italian subsidiaries of €4,065 million essentially related to the Exploration & Production segment. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,002 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit for €526(€3,014 million and ~~to a lower prospective tax rate~~€1,811 million in ~~relation to the windfall tax (the so-called Robin Tax) provided by Article 81 of the Legislative Decree No. 112/2008 which was assessed to be no more recoverable as,~~2018 and in ~~February 2015, by the Third Instance Court for €476 million. This sentence stated the illegitimacy of a tax rule prospectively, denying any reimbursement rights.~~2017, respectively).

4433 Earnings per share

2014 2015 2016
Weighted average number of shares used for the calculation of the basic and diluted earnings per share 3,610,387,582 3,601,140,133 3,601,140,133
Eni’s net profit (€ million) 1,303 �� (8,778) (1,464)
Basic and diluted earning (loss) per share (euro per share) 0.36 (2.44) (0.41)
Eni’s net profit - Continuing operations (€ million) 1,720 (7,952) (1,051)
Basic and diluted earning (loss) per share (euro per share) 0.48 (2.21) (0.29)
Eni’s net profit - Discontinued operations (€ million) (417) (826) (413)
Basic and diluted earning (loss) per share (euro per share) (0.12) (0.23) (0.12)

Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.

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The average number of ordinary shares used for the calculation of the basic earnings per share ~~outstanding at~~in 2019 was 3,592,249,603 (3,601,140,133 in 2018 and 2017).

Diluted earnings per share are calculated by dividing the net profit of the period attributable to Eni’s shareholders by the weighted average number of shares fully-diluted, excluding treasury shares, and including the number of potential shares to be issued in connection with stock-based compensation plans.

As of December 31, ~~2014, 2015 and 2016 was 3,610,387,582, 3,601,140,133 and 3,601,140,133, respectively.~~

~~There were no pending issues~~2019, the shares that could be potentially issued related the estimation of new shares that ~~could dilute~~will vest in connection with the 2017-2019 long-term monetary incentive plan.

Reconciliation of the weighted average number of shares used for the calculation for both basic and diluted earnings ~~at the reporting date.~~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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34 Exploration ~~and~~for evaluation of oil&gas resources


(€ million)	2014		2015		2016		2019		2018		2017
Revenues related to exploration activity and evaluation		1		68		4		34		17		9
Exploration activity and evaluation costs
- write-off of exploration and evaluation costs		1,110		617		170		214		93		252
- other exploration costs		368		254		204
- costs of geological and geophysical studies								275		287		273
Exploration expense for the year		1,478		871		374		489		380		525
Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs		1,081		735		1,092		1,031		1,081		995
Tangible assets: capitalized exploration and evaluation costs		2,577		2,637		2,818		1,563		1,267		1,371
Total tangible and intangible assets		3,658		3,372		3,910		2,594		2,348		2,366
Provision for decommissioning related to exploration activity and evaluation		126		131		118		109		77		81
Exploration expenditure (net cash used in investing activities)		1,030		566		417
Exploration expenditure (net cash used in investing activivties)								586		463		442
Geological and geophysical costs (cash flow from operating activities)		368		254		204		275		287		273
Total exploration effort		1,398		820		621		861		750		715

~~46 Segmental analysis~~35 Segment information and information by geographic area

~~Reportable segments~~Segment information

Eni’s segmental reporting reflects the Group’s operating segments, whose results are regularly reviewed by the chief operating decision maker (the CEO) to 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 to the CEO include segment revenues and directly attributable assets and liabilities.

Due to cessation of classification of the Chemical business as held for sale and the requirements that financial statements must be amended retrospectively to the date of initial classification (December 31, 2015) as though this disposal group never qualified as held for sale, the Group segmental reporting has been restated accordingly. The results of the Chemical business were aggregated with Refining & Marketing in a single reportable segment because these two operating segments exhibit similar economic characteristics. Furthermore, results of the E&P segment were restated following adoption of the Successful Efforts Method (SEM) (see note 1 – Basis of preparation).

As of December 31, ~~2016,~~2019, Eni had the following reportable segments:

•

Exploration & ~~Production:~~Production ~~is engaged~~: engages in ~~exploring for~~the research, development and ~~recovering~~production of crude oil and natural gas, including ~~participation~~projects to ~~projects for the~~build and operate liquefaction plants of ~~natural gas;~~LNG;

•

Gas & Power: ~~is engaged~~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 is also engaged in supply and marketing of crude oil and oil products targeting the operational requirements of Eni’s refining business and in energy commodity trading (including crude oil, natural gas, oil products, power, emission allowances, etc.) targeting to both hedge and stabilize the ~~Group~~Group’s industrial and commercial margins according to an integrated view and to optimize margins.

~~F-110~~

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•

Refining & Marketing and ~~Chemical:~~Chemical ~~is engaged~~: engages in the manufacturing, supply and distribution and marketing activities ~~for~~of oil products and chemical products. 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:~~Other activities ~~represents~~: include the ~~key support~~costs of the Group HQ functions which provide services to the operating subsidiaries, comprising ~~holdings~~holding, financing and treasury, ~~headquarters, central functions like~~ IT, HR, real estate, legal assistance, captive insurance, ~~activities,~~ as well as the results of the Group environmental ~~cleanup~~clean-up and remediation activities performed by the subsidiary ~~Syndial.~~Eni Rewind SpA (former Syndial SpA). The Energy Solutions Department, which engages in developing the ~~business of~~ renewable energy business, is an operating segment, which is reported within Corporate and ~~other~~Other activities because it does not meet the materiality threshold set by IFRS 8 for separate segment reporting.

~~The information~~

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Information by ~~segmental reporting~~segment is ~~the following:~~as follows:

Discontinued
operations
(€ million) Exploration &
Production Gas &
Power Refining &
Marketing
and Chemical Engineering &
Construction Corporate
and other
activities Adjustments
of intragroup
profits Total Engineering &
Construction Intragroup
eliminations Continuing
operations
2014
Net sales from operations(a)
28,488 73,434 28,994 12,873 1,429 54
Less: intersegment sales (16,618) (14,251) (2,042) (1,244) (1,270)
Net sales to customers 11,870 59,183 26,952 11,629 159 54 109,847 (11,629) 98,218
Operating profit 10,727 64 (2,811) 18 (518) 398 7,878 (18) 1,105 8,965
Net provisions for contingencies 29 (26) 152 154 188 (3) 494 (154) 340
Depreciation and amortization 6,916 335 381 737 70 (26) 8,413 (737) 7,676
Net Impairments/reversal 851 25 380 420 14 1,690 (420) 1,270
Write-off 1,197 1 1,198 1,198
Share of profit (loss) of equity-accounted investments 62 42 4 21 2 131 (21) 110
Identifiable assets(b)
72,917 19,342 13,313 14,210 1,300 (486) 120,596
Unallocated assets 29,770
Equity-accounted investments 2,016 772 228 120 36 3,172
Identifiable liabilities(c)
19,152 12,141 4,093 6,171 3,903 (165) 45,295
Unallocated liabilities 39,430
Capital expenditure 10,156 172 819 694 113 (82) 11,872
2015
Net sales from operations(a)
21,436 52,096 22,639 11,507 1,468
Less: intersegment sales (12,115) (9,917) (2,007) (1,243) (1,314)
Net sales to customers 9,321 42,179 20,632 10,264 154 82,550 (10,264) 72,286
Operating profit (959) (1,258) (1,567) (694) (497) (23) (4,998) 694 1,228 (3,076)
Net provisions for contingencies 221 41 148 104 226 8 748 (104) 644
Depreciation and amortization 8,080 363 454 618 71 (28) 9,558 (618) 8,940
Net Impairments/reversal 5,212 152 1,150 590 20 7,124 (590) 6,534
Write-off 686 2 688 688
Share of profit (loss) of equity-accounted investments (446) (2) (20) 17 (3) (454) (17) (471)
Identifiable assets(b)
73,073 14,290 10,483 13,608 1,117 (543) 112,028
Unallocated assets 26,973
Equity-accounted investments 1,884 690 243 134 36 2,987 (134) 2,853
Identifiable liabilities(c)
17,742 9,313 3,657 5,861 3,824 (199) 40,198
Unallocated liabilities 41,394
Capital expenditure 9,980 154 628 561 64 (85) 11,302
2016
Net sales from operations(a)
16,089 40,961 18,733 1,343
Less: intersegment sales (9,711) (8,898) (1,605) (1,150)
Net sales to customers 6,378 32,063 17,128 193 55,762 55,762
Operating profit 2,567 (391) 723 (681) (61) 2,157 2,157
Net provisions for contingencies 123 50 171 438 (277) 505 505
Depreciation and amortization 6,772 354 389 72 (28) 7,559 7,559
Net Impairments/reversal (700) 81 104 40 (475) (475)
Write-off 153 2 195 350 350
Share of profit (loss) of equity-accounted investments (198) 19 (3) (144) (326) (326)
Identifiable assets(b)
75,716 12,014 10,712 1,146 (520) 99,068
Unallocated assets 25,477
Equity-accounted investments 1,626 592 289 1,533 4,040
Identifiable liabilities(c)
17,433 8,923 3,968 3,939 (332) 33,931
Unallocated liabilities 37,528
Capital expenditure 8,254 120 664 55 87 9,180

(€ 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

(a)

~~Before elimination~~Include assets directly associated with the generation of ~~intersegment sales.~~operating profit.

(b)

~~Includes~~Include assets not directly associated with the generation of operating profit.

(c)

~~Includes~~Include liabilities directly associated with the generation of operating profit.

(d)

Include liabilities not directly associated with the generation of operating profit.

~~F-111~~F-113

TABLE OF CONTENTS

~~Financial information~~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
2014
2019
Identifiable assets(a)																		19,346		7,237		1,151		5,230		17,898		40,021		912		91,795
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets																		1,402		306		9		1,017		1,685		3,902		55		8,376
2018
Identifiable assets(a)		26,722		15,254		9,099		8,559		21,105		37,976		1,881		120,596		18,646		7,086		1,031		4,546		16,910		36,155		1,109		85,483
Capital expenditure in tangible and intangible assets		1,757		827		1,378		1,165		1,904		4,689		152		11,872		1,424		267		538		534		1,782		4,533		41		9,119
2015
2017
Identifiable assets(a)		21,360		12,370		7,937		7,442		22,359		38,927		1,633		112,028		18,449		7,706		6,160		4,406		16,527		35,385		1,183		89,816
Capital expenditure in tangible and intangible assets		1,320		708		1,151		727		2,326		5,020		50		11,302		1,090		316		387		278		898		5,699		13		8,681
2016
Identifiable assets(a)		18,769		7,370		6,960		5,397		19,471		39,812		1,289		99,068
Capital expenditure in tangible and intangible assets		1,163		331		460		233		1,978		5,004		11		9,180

(a)

~~Includes~~Include assets directly associated with the generation of operating profit.

Sales from operations by geographical area of destination


(€ million)	2014		2015		2016		2019		2018		2017
Italy		29,234		24,405		21,280		23,312		25,279		21,925
Other European Union		29,298		20,730		15,808		18,567		20,408		19,791
Rest of Europe		11,975		7,125		4,804		6,931		7,052		5,911
Americas		5,763		4,217		3,212		3,842		5,051		5,154
Asia		12,840		9,086		5,619		8,102		9,585		7,523
Africa		8,786		6,482		4,865		8,998		8,246		6,428
Other areas		322		241		174		129		201		187
		98,218		72,286		55,762		69,881		75,822		66,919

4736 Transactions with related parties

In the ordinary course of its business, Eni enters into transactions regarding:

(a)

~~exchange~~Purchase/supply of goods and services and the provision of ~~services and~~ financing ~~with~~to joint ventures, associates and non-consolidated subsidiaries;

(b)

~~exchange~~Purchase/supply of goods and ~~provision of~~ services ~~with~~to entities controlled by the Italian Government;

(c)

~~relations with Vodafone Italia SpA~~Purchase/supply of goods and services to companies related to Eni SpA through ~~a member~~members of the Board of Directors. ~~These~~Most of these transactions ~~mainly involve costs for mobile communication services for €7 million, awarded following a competitive procedure, and therefore exempted~~are exempt from the application of the Eni internal procedure ~~of Eni~~ “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 ~~if not exempted,~~standard conditions, or because they fall below the materiality threshold provided for by the procedure. The solely non-exempted transaction, that was positively ~~evaluated~~examined and valued in ~~accordance~~application of the procedure, concerned the remote monitoring of cars in the “enjoy” initiative (for an amount of about €1 million) conducted with ~~such procedure;~~Vodafone Italia SpA related to Eni SpA through of a member of the Board of Directors; and

(d)

contributions to non-profit entities ~~with a non-company form referable~~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 ~~research~~scientific and ~~development;~~technological research; and (ii) Eni Enrico Mattei Foundation, established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge enrichment in the fields of economics, energy and environment, both at the national and international level.

Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business.

~~F-112~~F-114

TABLE OF CONTENTS

~~Trade~~Transactions and ~~other transactions~~balances with related parties

(€ million)	December 31, 2014						2014														December 31, 2019						2019
	Receivables and other assets		Payables and other liabilities		Guarantees		Costs						Revenues						Other operating (expense) income
Name							Goods		Services		Other		Goods		Services		Other		Other operating (expense) income		Receivables and other assets		Payables and other liabilities		Guarantees		Revenues		Costs		Other operating (expense) income
Continuing operations
Joint ventures and associates
Agiba Petroleum Co		2		60						169												3		71						229
CEPAV (Consorzio Eni per l’Alta Velocità) Due		120		152
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		23		12		6,122
EnBW Eni Verwaltungsgesellschaft mbH														134		2
InAgip doo		52		11						44				1		7
Angola LNG Supply Services Llc																										181
Coral FLNG SA																						15				1,168		71
Gas Distribution Company of Thessaloniki - Thessaly SA																								13						53
Saipem Group																						75		227		510		27		503
Karachaganak Petroleum Operating BV		43		233				1,246		320		22				20						33		198				1		1,134
KWANDA - Suporte Logistico Lda		68		15
Mellitah Oil & Gas BV		98		58				10		235						7						57		171				3		365
Petrobel Belayim Petroleum Co		32		375						603						2						50		1,130				7		1,590
Petromar Lda		93		4		21
South Stream Transport BV																		1
Unión Fenosa Gas Comercializadora SA		15		1										157
Unión Fenosa Gas SA						57				1		1										8		1		57		1		6		63
Vår Energi AS																						32		143		482		63		1,481		(64)
Other(*)		122		67				17		132		18		95		61		15				106		29		1		112		87
		668		988		6,200		1,273		1,504		41		387		99		16				379		1,983		2,399		285		5,448		(1)
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV										342		7				32		2
Eni BTC Ltd						167																				180
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		61		1		10										3						101		1		3		14
Other(*)		13		52		1				11				4		2		4
Other																						5		25		14		6		18
		74		53		178				353		7		4		37		6				106		26		197		20		18
		742		1,041		6,378		1,273		1,857		48		391		136		22				485		2,009		2,596		305		5,466		(1)
Entities controlled by the Government
Enel Group		156		122						933				181		133		1		183		185		284				105		602		(8)
Italgas Group																						3		154				1		677
Snam Group		147		585		7		155		1,867		5		235		33				13		278		229				71		1,208
Terna Group		33		65				89		154		7		120		35		44		12		40		45				171		223		17
GSE - Gestore Servizi Energetici		88		124				580		2		60		172		14						26		24				549		468		11
Other(*)		44		93				8		98		3		45		2		2
Other																						10		19				12		35
		468		989		7		832		3,054		75		753		217		47		208		542		755				909		3,213		20
Pension funds and foundations				2						4		60
Other related parties																						2		3				5		37
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»																						75		74				33		457
		1,210		2,032		6,385		2,105		4,915		183		1,144		353		69		208		1,104		2,841		2,596		1,252		9,173		19
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due										159						216
CEPAV (Consorzio Eni per l’Alta Velocità) Uno										3						14
KWANDA - Suporte Logistico Lda										10						9
Petrobel Belayim Petroleum Co																83
Petromar Lda										1		1				61
South Stream Transport BV																495
Other(*)										50						31
										223		1				909
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV																155
Other(*)										2
										2						155
Entities controlled by the Government
Snam Group																39
Other(*)										13						4
										13						43
Pension funds and foundations												1
										238		2				1,107
		1,210		2,032		6,385		2,105		5,153		185		1,144		1,460		69		208

(*)

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-113~~F-115

TABLE OF CONTENTS

(€ million)
December 31, 2015 2015
Receivables
and other
assets Payables
and other
liabilities Guarantees Costs Revenues Other
operating
(expense)
income
Name Goods Services Other Goods Services Other
Continuing operations
Joint ventures and associates
Agiba Petroleum Co 6 60 187
CEPAV (Consorzio Eni per l’Alta Velocità) Due 1
CEPAV (Consorzio Eni per l’Alta Velocità) Uno 6,122
Karachaganak Petroleum Operating BV 48 171 748 403 8 10
Mellitah Oil & Gas BV 8 16 46 339 19
Petrobel Belayim Petroleum Co 16 183 543
Petromar Lda 2 6
Unión Fenosa Gas SA 1 57 (4)
Other(*) 118 42 27 124 1 60 70 37 (2)
199 473 6,185 821 1,596 9 60 99 37 (6)
Unconsolidated entities controlled by Eni
Eni México S. de RL de CV 101
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) 65 1 9 3
Other(*) 17 19 3 2 2 4 2 2
82 20 113 2 2 4 5 2
281 493 6,298 823 1,598 9 64 104 39 (6)
Entities controlled by the Government
Enel Group 138 203 1,063 196 134 90
Snam Group 144 522 3 137 2,014 5 249 24 1
Terna Group 18 42 109 125 14 77 19 29 12
GSE - Gestore Servizi Energetici 44 63 419 5 35 307 43
Other(*) 22 38 56 6 29 1
366 868 3 665 3,263 60 858 221 30 102
Pension funds and foundations 1 2 4 50
Groupement Sonatrach - Agip and Organe Conjoint des Opérations 185 300 453 12 35 60
833 1,663 6,301 1,488 5,318 131 957 385 69 96
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due 60 99 68 101 145
CEPAV (Consorzio Eni per l’Alta Velocità) Uno 9 3 3 1
KWANDA - Suporte Logistico Lda 69 10 5 8
Mellitah Oil & Gas BV 9 7
Petrobel Belayim Petroleum Co 19 86
Petromar Lda 97 16 16 45
Other(*) 14 27 10 54 1 21 1
277 155 68 10 181 5 1 306 1
Unconsolidated entities controlled by Eni
Other(*) 1 1 2
1 1 2
Entities controlled by the Government
Snam Group 25 46 36
Other(*) 5 3
25 51 3 36
Pension funds and foundations 1
303 207 68 10 �� 186 6 1 342 1
1,136 1,870 6,369 1,498 5,504 137 958 727 70 96

~~(*)~~

~~Each individual amount included herein was lower than €50 million.~~

~~F-114~~

~~TABLE OF CONTENTS~~

(€ million)																					December 31, 2017						2017
	December 31, 2016						2016
	Receivables and other assets		Payables and other liabilities		Guarantees		Costs						Revenues						Other operating (expense) income
Name							Goods		Services		Other		Goods		Services		Other		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		50						156												1		83						142
Saipem Group		64		224		8,094				775		6		9		37		5
Coral FLNG SA																						20		4		1,094		28
Karachaganak Petroleum Operating BV		47		187				573		333		12		7		1		19				36		121						951
Mellitah Oil & Gas BV		7		134				5		472												5		220				2		495
Petrobel Belayim Petroleum Co		225		532						1,940								2				86		1,205				8		3,168
Saipem Group																						63		76		7,270		44		450
Unión Fenosa Gas SA						57								93				1								57		202		3		28
Other(*)		114		25		1		32		113				86		44		13		47		84		22				128		140
		458		1,152		8,152		610		3,789		18		195		82		40		47		295		1,731		8,421		412		5,349		28
Unconsolidated entities controlled by Eni
Eni BTC Ltd						192																				169
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		69		1		3										2						77		1		5		7
Other(*)		9		16		51		4		4				6		2		2
Other																						20		23		7		7		14
		78		17		246		4		4				6		4		2				97		24		181		14		14
		536		1,169		8,398		614		3,793		18		201		86		42		47		392		1,755		8,602		426		5,363		28
Entities controlled by the Government
Enel Group		151		254				28		780				88		95		18		182		123		187				164		622		285
GSE - Gestore Servizi Energetici																						69		219				702		506		2
Italgas Group																						14		180		1		18		681
Snam Group		44		541		1		125		1,902		5		99		14						187		351				85		1,221
Terna Group		33		46				60		165		7		61		56				13		35		31				154		212		15
GSE - Gestore Servizi Energetici		58		32				206		5		32		344		68		2		5
Italgas Group		54		1						4
Other(*)		43		24						37				62		6						50		21				16		38		1
		383		898		1		419		2,893		44		654		239		20		200		478		989		1		1,139		3,280		303
Pension funds and foundations				2						4		28
Groupement Sonatrach - Agip and Organe Conjoint des Opérations		176		331				5		413		5				58		12
Other related parties																						1		2				1		25
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»																						39		145				42		530
		1,095		2,400		8,399		1,038		7,103		95		855		383		74		247		910		2,891		8,603		1,608		9,198		331

(*)

Each individual amount included herein was lower than €50 million.

The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

•

Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach — Agip «GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for Karachaganak Petroleum Operating BV, purchase of crude oil ~~products~~ by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs;

•

a guarantee issued on behalf of Angola LNG Supply Services Llc to cover the commitments relating to the payment of the regasification fee;

•

supply of upstream specialist services and a guarantee issued on a pro-quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant (for more information see note 27 — Guarantees, commitments and risks);

•

the acquisition of transport and distribution services from the Gas Distribution Company of Thessaloniki-Thessaly SA;

•

engineering, construction and drilling services by the Saipem Group mainly for the Exploration & Production segment and residual guarantees issued by Eni SpA relating to bid bonds and performance bonds;

•

a performance ~~guarantees~~guarantee given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and ~~sales~~fair value of ~~LNG;~~derivative financial instruments;

•

a guarantee 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 of derivative financial instruments;

•

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).

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TABLE OF CONTENTS

The most significant transactions with entities controlled by the Italian Government concerned:

•

sale of ~~diesel~~ fuel, ~~and fuel through payment cards,~~ sale and purchase of gas, ~~environmental certificates, transmission~~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 ~~the~~ Snam Group and ~~the~~ Italgas Group on the basis of tariffs set by the Italian Regulatory Authority for ~~Electricity, Gas~~Energy, Networks and ~~Water~~Environment and purchase and sale with Snam Group of natural gas for granting the system balancing ~~of the system~~ on the basis of prices referred to the quotations of the main energy commodities;

•

~~sale and purchase of electricity, the~~ acquisition of domestic electricity transmission service and sale and purchase of electricity for granting the system balancing 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 ~~the~~ Terna Group;

~~F-115~~

~~TABLE OF CONTENTS~~

•

sale and purchase of electricity, ~~and~~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.

Transactions with ~~pension funds and foundation~~other related parties concerned:

•

provisions to pension funds of ~~€24~~€30 million; and

•

contributions and service provisions to Eni Enrico Mattei Foundation ~~of €4~~for €6 million and to Eni ~~Enrico Mattei~~ Foundation for €4€1 million.

Financing transactions and balances with related parties

(€ million)
December 31, 2014 2014
Name Receivables Payables Guarantees Charges Gains
Continuing operations
Joint ventures and associates
CARDÓN IV SA 621 29
CEPAV (Consorzio Eni per l’Alta Velocità) Due 150 6
Matrìca SpA 200 5
Shatskmorneftegaz Sàrl 56 13
Société Centrale Electrique du Congo SA 84 2
Unión Fenosa Gas SA 90
Other(*) 48 13 19 28 4
1,009 103 171 41 44
Unconsolidated entities controlled by Eni
Other(*) 68 73 2 1
68 73 2 1
Entities controlled by the Government
Other(*) 5 1
5 1
1,077 181 173 41 46

~~(*)~~

~~Each individual amount included herein was lower than €50 million.~~

(€ million)
December 31, 2015 2015
Name Receivables Payables Guarantees Charges Gains
Continuing operations
Joint ventures and associates
CARDÓN IV SA 1,112 65
Matrìca SpA 209 10 11
Shatskmorneftegaz Sàrl 63 21
Société Centrale Electrique du Congo SA 94
Unión Fenosa Gas SA 90
Other(*) 52 7 12 19 5
1,530 97 12 50 81
Unconsolidated entities controlled by Eni
Other(*) 51 111 �� 1
51 111 1
Entities controlled by the Government
Other(*) 27 1
27 1
1,608 208 12 50 83
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due 150
Other(*) 5
5 150
1,613 208 162 50 83

~~(*)~~

~~Each individual amount included herein was lower than €50 million.~~

(€ 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

~~F-116~~F-117

TABLE OF CONTENTS

(€ million)
	December 31, 2016						2016						December 31, 2017						2017
Name	Receivables		Payables		Guarantees		Charges		Gains		Income from equity instruments		Receivables		Payables		Guarantees		Gains		Charges
Continuing operations
Joint ventures and associates
CARDÓN IV SA		1,054								96
Matrìca SpA		125						93		9
Angola LNG Ltd																		233
Coral South FLNG D MCC																		1,334
Cardón IV SA														955						86
Shatskmorneftegaz Sarl		69						13		4				101						6
Société Centrale Electrique du Congo SA		78						18						66		43
Unión Fenosa Gas SA				85
Saipem Group						82				43		27				3		56		13
Other(*)		52				2		17		4
Coral FLNG SA														56						71
Other														48		49		2		14		1
		1,378		85		84		141		156		27		1,226		95		1,625		190		1
Unconsolidated entities controlled by Eni
Eni BTC Ltd				54
Servizi Fondo Bombole Metano SpA														60		9				1
Other(*)		46		52				1		1				1		52
		46		106				1		1				61		61				1
Entities controlled by the Government
Other(*)								3
Other																8						3
								3								8						3
		1,424		191		84		145		157		27		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 ~~loans~~loan granted to ~~CARDÓN~~Cardón IV SA for the exploration and development activities of a gas field in Venezuela;

•

the financing ~~loans~~loan granted to ~~Matrìca SpA~~Coral FLNG SA for the construction of a floating gas liquefaction plant in ~~relation to the “Green Chemistry” project at the Porto Torres plant;~~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 ~~loans~~of the Coral FLNG development project (for more information see note 27 — Guarantees, commitments and risks);

•

the loan granted ~~to Shatskmorneftegaz Sàrl for the exploration activity of in the Black Sea and~~ to Société Centrale Electrique du Congo SA for the construction of ~~an electric~~a power plant in ~~Congo;~~Congo.

•

~~a cash deposit at Eni’s financial companies on behalf of Unión Fenosa Gas SA and Eni BTC Ltd;~~

•

~~derivative financial instruments relating to the settlement of derivatives on exchange rate entered into by the Saipem Group with Eni in previous years.~~

On January 22, 2016, Eni closed the sale transaction of 12.503% of the share capital of Saipem to CDP Equity SpA (former Fondo Strategico Italiano SpA) for a total consideration of €463 million. More information is reported in note 35 — Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale.

~~F-117~~

~~TABLE OF CONTENTS~~

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, 2014						December 31, 2015						December 31, 2016						December 31, 2019						December 31, 2018
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
																			Total		Related parties		Impact %		Total		Related parties		Impact %
Other current financial assets																				384		60		15.63		300		49		16.33
Trade and other receivables		28,601		1,973		6.90		21,640		1,985		9.17		17,593		1,100		6.25		12,873		704		5.47		14,101		633		4.49
Other current assets		4,385		43		0.98		3,642		50		1.37		2,591		57		2.20		3,972		219		5.51		2,819		71		2.52
Other non-current financial assets		1,042		259		24.86		1,026		396		38.60		1,860		1,349		72.53		1,174		911		77.60		1,253		915		73.02
Other non-current assets		2,773		12		0.43		1,758		10		0.57		1,348		13		0.96		871		181		20.78		624		160		25.64
Discontinued operations and assets held for sale		456						15,533		308		1.98		14
Current financial liabilities		2,716		181		6.66		5,720		208		3.64		3,396		191		5.62
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		23,703		1,954		8.24		14,942		1,544		10.33		16,703		2,289		13.70		15,545		2,663		17.13		16,747		3,664		21.88
Other current liabilities		4,489		58		1.29		4,712		96		2.04		2,599		88		3.39		7,146		155		2.17		5,412		63		1.16
Long-term lease liabilities																				4,759		8		0.17
Other non-current liabilities		2,285		20		0.88		1,852		23		1.24		1,768		23		1.30		1,611		23		1.43		1,475		23		1.56
Discontinued operations and liabilities directly associated to assets held for sale		165						6,485		207		3.19

F-118

TABLE OF CONTENTS

The impact of transactions with related parties on the profit and loss accounts consisted of the following:

2014 2015 2016
(€ million) Total Related
parties Impact % Total Related
parties Impact % Total Related
parties Impact %
Continuing operations
Net sales from operations 98,218 1,497 1.52 72,286 1,342 1.86 55,762 1,238 2.22
Other income and revenues 1,079 69 6.39 1,252 69 5.51 931 74 7.95
Purchases, services and other 77,404 7,143 9.23 56,848 6,882 12.11 44,124 8,212 18.61
Payroll and related costs 2,929 60 2.05 3,119 55 1.76 2,994 24 0.80
Other operating (expense) income 145 208 — (485) 96 — 16 247 —
Financial income 5,701 46 0.81 8,635 83 0.96 5,850 157 2.69
Financial expense (7,057) (41) 0.58 (10,104) (50) 0.49 (6,232) (145) 2.33
Derivative financial instruments 165 160 (482) 27 —
Discontinued operations
Total revenues 11,644 1,107 9.51 10,277 344 3.35
Operating costs 12,731 240 1.89 12,199 202 1.66


	2019						2018						2017
(€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
Other income and revenues		1,160		4		0.34		1,116		8		0.72		4,058		41		1.01
Purchases, services and other		(50,874)		(9,173)		18.03		(55,622)		(8,009)		14.40		(51,548)		(9,164)		17.78
Net (impairment losses) reversals of trade and other receivables		(432)		28		—		(415)		26		—		(913)
Payroll and related costs		(2,996)		(28)		0.93		(3,093)		(22)		0.71		(2,951)		(34)		1.15
Other operating income (expense)		287		19		6.62		129		319		—		(32)		331		—
Finance income		3,087		96		3.11		3,967		115		2.90		3,924		191		4.87
Finance expense		(4,079)		(36)		0.88		(4,663)		(283)		6.07		(5,886)		(4)		0.07

Main cash flows with related parties are provided below:

(€ million) 2014 2015 2016
Revenues and other income 1,566 1,411 1,312
Costs and other expenses (6,022) (5,786) (5,623)
Other operating income (loss) 208 96 247
Net change in trade and other receivables and liabilities 164 105 182
Net interests 46 82 133
Net cash provided from operating activities — Continuing operations (4,038) (4,092) (3,749)
Net cash provided from operating activities — Discontinued operations 835 126
Net cash provided from operating activities (3,203) (3,966) (3,749)
Capital expenditure in tangible and intangible assets (1,181) (1,151) (2,613)
Disposal of investments 463
Net change in accounts payable and receivable in relation to investments (114) (238) 252
Change in financial receivables (163) (194) 5,650
Net cash used in investing activities (1,458) (1,583) 3,752
Change in financial liabilities (99) 13 (192)
Net cash used in financing activities (99) 13 (192)
Total financial flows to related parties (4,760) (5,536) (189)

~~F-118~~

~~TABLE OF CONTENTS~~


(€ million)	2019		2018		2017
Revenues and other income		1,252		1,391		1,608
Costs and other expenses		(6,869)		(5,210)		(5,360)
Other operating income (expense)		19		319		331
Net change in trade and other receivables and payables		(839)		683		391
Net interests		81		110		187
Net cash provided from operating activities		(6,356)		(2,707)		(2,843)
Capital expenditure in tangible and intangible assets		(2,332)		(2,768)		(3,838)
Net change in accounts payable and receivable in relation to investments		(339)		20		425
Change in financial receivables		(241)		(566)		298
Net cash used in investing activities		(2,912)		(3,314)		(3,115)
Change in financial and lease liabilities		(817)		16		(16)
Net cash used in financing activities		(817)		16		(16)
Total financial flows to related parties		(10,085)		(6,005)		(5,974)

The impact of cash flows with related parties consisted of the following:


	2014						2015						2016						2019						2018						2017
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
Cash provided from operating activities		14,742		(3,203)		—		11,649		(3,966)		—		7,673		(3,749)		—
Cash used in investing activities		(8,575)		(1,458)		17.00		(10,923)		(1,583)		14.49		(4,443)		3,752		—
Cash used in financing activities		(5,062)		(99)		1.96		(1,351)		13		—		(3,651)		(192)		5.26

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

37 Other information about investments

Information on Eni’s investments as of December 31, ~~2016~~2019

The following section provides ~~the~~ information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, ~~2016.~~2019. 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 25.76
Ministero
dell’Economia e delle
Finanze 4.34
Eni SpA 0.91
Other shareholders 68.99

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

4.34

1.70

68.20

Subsidiaries

Exploration & Production

In 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(*)

Eni Angola SpA

San Donato
Milanese (MI)

Angola

EUR

20,200,000

Eni SpA

100.00

F.C.

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.

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.

San Donato
Milanese (MI)

Mozambique

EUR

200,000

Eni SpA

100.00

F.C.

Eni Timor Leste SpA

San Donato
Milanese (MI)

Timor Leste

EUR

6,841,517

Eni SpA

100.00

F.C.

San Donato
Milanese (MI)

East Timor

EUR

6,841,517

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.

San Donato
Milanese (MI)

Angola

EUR

10,000,000

Eni SpA

100.00

F.C.

Eni Zubair SpA
(in liquidation)

San Donato
Milanese (MI)

Italy

EUR

120,000

Eni SpA

100.00

Co.

EniProgetti SpA

Venezia
Marghera (VE)

Italy

EUR

2,064,000

Eni SpA

100.00

F.C.

Floaters SpA

San Donato
Milanese (MI)

Italy

EUR

200,120,000

Eni SpA

100.00

F.C.

San Donato
Milanese (MI)

Italy

EUR

200,120,000

Eni SpA

100.00

F.C.

Ieoc SpA

San Donato
Milanese (MI)

Egypt

EUR

18,331,000

Eni SpA

100.00

F.C.

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

24,103,200

Eni SpA
Third parties

99.96
0.04

99.96

F.C.

San Donato
Milanese (MI)

Italy

EUR

13,877,600

Eni SpA

Third parties

99.96

0.04

99.96

F.C.

Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA

Venezia
Marghera (VE)

Italy

EUR

2,064,000

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

(#)

Company with shares quoted in the regulated market of Italy or of other EU countries

~~F-119~~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(*)

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.

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.

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.

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,005

Eni International BV

100.00

F.C.

Agip Oil Ecuador BV

Amsterdam
(Netherlands)

Ecuador

EUR

20,000

Eni International BV

100.00

F.C.

Agip Oleoducto de Crudos Pesados BV

Amsterdam
(Netherlands)

Ecuador

EUR

20,000

Eni International BV

100.00

Eq.

Burren (Cyprus) Holdings Ltd (in liquidation)

Nicosia
(Cyprus)

Cyprus

EUR

1,710

Burren En.(Berm)Ltd

100.00

Co.

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

F.C.

Hamilton
(Bermuda)

United
Kingdom

USD

12,002

Burren Energy Plc

100.00

F.C.

Burren Energy (Egypt) Ltd

London
(United
Kingdom)

Egypt

GBP

Burren Energy Plc

100.00

Eq.

Burren Energy Congo Ltd

Tortola
(British Virgin
Islands)

Republic of
the Congo

USD

50,000

Burren En.(Berm)Ltd

100.00

F.C.

Tortola
(British Virgin
Islands)

Republic of
the Congo

USD

50,000

Burren En.(Berm)Ltd

100.00

F.C.

Burren Energy (Egypt) Ltd

London
(United
Kingdom)

Egypt

GBP

Burren Energy Plc

100.00

Eq.

Burren Energy India Ltd

London
(United
Kingdom)

United
Kingdom

GBP

Burren Energy Plc

100.00

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

Burren Energy Plc

100.00

F.C.

Burren Energy Ltd (in liquidation)

Nicosia
(Cyprus)

Cyprus

EUR

3,420

Burren En.(Berm)Ltd

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.

London
(United
Kingdom)

United
Kingdom

GBP

28,819,023

Eni UK Holding Plc
Eni UK Ltd

99.99
(..)

100.00

F.C.

Burren Energy (Services)
Ltd (in liquidation)

London
(United
Kingdom)

United
Kingdom

GBP

Burren Energy Plc

100.00

F.C.

Burren Energy Ship Management Ltd (in liquidation)

Nicosia
(Cyprus)

Cyprus

EUR

3,420

Burren(Cyp)Hold.Ltd
(L)
Burren En.(Berm)Ltd

50.00

50.00

Co.

Burren Energy Shipping
and Transportation Ltd
(in liquidation)

Nicosia
(Cyprus)

Cyprus

EUR

3,420

Burren(Cyp)Hold.Ltd
(L)
Burren En.(Berm)Ltd

50.00

50.00

Co.

Burren Shakti Ltd

Hamilton
(Bermuda)

United
Kingdom

USD

65,300,000

Burren En. India Ltd

100.00

F.C.

Hamilton
(Bermuda)

United
Kingdom

USD

213,138

Burren En. India Ltd

100.00

F.C.

Eni Abu Dhabi BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Amsterdam
(Netherlands)

United Arab
Emirates

EUR

20,000

Eni International BV

100.00

F.C.

Eni AEP Ltd

London
(United
Kingdom)

Pakistan

GBP

73,471,000

Eni UK Ltd

100.00

F.C.

London
(United
Kingdom)

Pakistan

GBP

13,471,000

Eni UK Ltd

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

F.C.

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.

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.

Amsterdam
(Netherlands)

Algeria

EUR

20,000

Eni International BV

100.00

F.C.

Eni Ambalat Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni America Ltd

Dover, Delaware
(USA)

USA

USD

72,000

Eni UHL Ltd

100.00

F.C.

Dover, Delaware
(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.

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

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-120~~F-121

TABLE OF CONTENTS

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(*)

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

24,136,336

Eni International BV
Eni Oil Holdings BV

95.00
5.00

Eq.

Eni Arguni I Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Australia BV

Amsterdam
(Netherlands)

Australia

EUR

20,000

Eni International BV

100.00

F.C.

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.

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

F.C.

Eni BB Petroleum Inc

Dover,
Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Dover,
Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni BTC Ltd

London
(United Kingdom)

United
Kingdom

GBP

34,000,000

Eni International BV

100.00

Eq.

London
(United
Kingdom)

United
Kingdom

GBP

Eni International BV

100.00

Eq.

Eni Bukat Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Bulungan BV

Amsterdam
(Netherlands)

Indonesia

EUR

20,000

Eni International BV

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

F.C.

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

F.C.

London
(United
Kingdom)

Indonesia

USD

2,210,728

Eni Lasmo Plc

100.00

F.C.

Eni China BV

Amsterdam
(Netherlands)

China

EUR

20,000

Eni International BV

100.00

F.C.

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.

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
(former Eni Ivory
Coast Ltd)

London
(United Kingdom)

Ivory Coast

GBP

Eni UK Ltd

100.00

F.C.

Eni Croatia BV

Amsterdam
(Netherlands)

Croatia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Côte d’Ivoire Ltd

London
(United
Kingdom)

Ivory Coast

GBP

Eni Lasmo Plc

100.00

F.C.

Eni Cyprus Ltd

Nicosia
(Cyprus)

Cyprus

EUR

2,004

Eni International BV

100.00

F.C.

Nicosia
(Cyprus)

Cyprus

EUR

2,006

Eni International BV

100.00

F.C.

Eni Dación BV

Amsterdam
(Netherlands)

Netherlands

EUR

90,000

Eni Oil Holdings BV

100.00

F.C.

Eni Denmark BV

Amsterdam
(Netherlands)

Greenland

EUR

20,000

Eni International BV

100.00

F.C.

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.

Rio de Janeiro
(Brazil)

Brazil

BRL

1,593,415,000

Eni International BV
Eni Oil Holdings BV

99.99

(..)

Eq.

Eni East Ganal Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni East Sepinggan
Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Elgin/Franklin Ltd

London
(United Kingdom)

United
Kingdom

GBP

100

Eni UK Ltd

100.00

F.C.

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.

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Engineering E&P Ltd

London
(United Kingdom)

United
Kingdom

GBP

40,000,001

Eni UK Ltd

100.00

F.C.

Eni Exploration & Production
Holding BV

Amsterdam
(Netherlands)

Netherlands

EUR

29,832,777.12

Eni International BV

100.00

F.C.

Amsterdam
(Netherlands)

Netherlands

EUR

29,832,777.12

Eni International BV

100.00

F.C.

Eni Gabon SA

Libreville (Gabon)

Gabon

XAF

13,132,000,000

Eni International BV

100.00

F.C.

Libreville
(Gabon)

Gabon

XAF

13,132,000,000

Eni International BV

100.00

F.C.

Eni Ganal Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

~~F-121~~F-122

TABLE OF CONTENTS

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(*)

Eni Gas & Power LNG Australia BV

Amsterdam
(Netherlands)

Australia

EUR

10,000,000

Eni International BV

100.00

F.C.

Amsterdam
(Netherlands)

Australia

EUR

10,000,000

Eni International BV

100.00

F.C.

Eni Ghana
Exploration and
Production Ltd

Accra (Ghana)

Ghana

GHS

21,412,500

Eni International BV

100.00

F.C.

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.

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.

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 UK Ltd

100.00

F.C.

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.

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.

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.

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.

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

F.C.

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.

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.

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.

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.

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.

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.

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.

Amsterdam
(Netherlands)

Kenya

EUR

20,000

Eni International BV

100.00

F.C.

Eni Krueng Mane Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Lasmo Plc

London
(United Kingdom)

United
Kingdom

GBP

337,638,724.25

Eni Investments Plc
Eni UK Ltd

99.99
(—)

100.00

F.C.

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 Liberia BV

Amsterdam
(Netherlands)

Liberia

EUR

20,000

Eni International BV

100.00

F.C.

Amsterdam
(Netherlands)

Liberia

EUR

20,000

Eni International BV

100.00

Eq.

Eni Liverpool Bay Operating Co Ltd

London
(United Kingdom)

United
Kingdom

GBP

5,001,000

Eni UK Ltd

100.00

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

Eni UK Ltd

100.00

Eq.

Eni LNS Ltd

London
(United Kingdom)

United
Kingdom

GBP

80,400,000

Eni UK Ltd

100.00

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

80,400,000

Eni UK Ltd

100.00

F.C.

Eni Marketing Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Dover, Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Maroc BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Amsterdam
(Netherlands)

Morocco

EUR

20,000

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-122~~F-123

TABLE OF CONTENTS

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(*)

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.

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 BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Eni Middle East Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

100.00

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

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.

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

Eq.

Amsterdam
(Netherlands)

Montenegro

EUR

20,000

Eni International BV

100.00

F.C.

Eni Mozambique Engineering Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni UK Ltd

100.00

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

Eni Lasmo Plc

100.00

F.C.

Eni Mozambique LNG Holding BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

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.

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.

Amsterdam
(Netherlands)

Myanmar

EUR

20,000

Eni International BV

100.00

F.C.

Eni Norge AS

Forus
(Norway)

Norway

NOK

278,000,000

Eni International BV

100.00

F.C.

Eni North Africa BV

Amsterdam
(Netherlands)

Libya

EUR

20,000

Eni International BV

100.00

F.C.

Amsterdam
(Netherlands)

Libya

EUR

20,000

Eni International BV

100.00

F.C.

Eni North Ganal Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Oil & Gas Inc

Dover, Delaware
(USA)

USA

USD

100,800

Eni America Ltd

100.00

F.C.

Dover,
Delaware
(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.

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.

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.

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.

Luxembourg
(Luxembourg)

Pakistan

USD

20,000

Eni Oil Holdings BV

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.

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

F.C.

Dover,
Delaware
(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

F.C.

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

F.C.

Eni Rapak Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni RD Congo SA

Kinshasa
(Democratic
Republic
of Congo)

Democratic
Republic of
Congo

CDF

750,000,000

Eni International BV
Eni Oil Holdings BV

99.99
(—)

100.00

F.C.

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.

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.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

~~F-123~~F-124

TABLE OF CONTENTS

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(*)

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.

Aberdeen
(United
Kingdom)

United
Kingdom

GBP

1,000

Eni UK Ltd

100.00

F.C.

Eni Togo BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Eni Trinidad and Tobago Ltd

Port Of Spain
(Trinidad and
Tobago)

Trinidad and
Tobago

TTD

1,181,880

Eni International BV

100.00

F.C.

Eni Tunisia BV

Amsterdam
(Netherlands)

Tunisia

EUR

20,000

Eni International BV

100.00

F.C.

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.

Hamilton
(Bermuda)

Turkmenistan

USD

20,000

Burren En.(Berm)Ltd

100.00

F.C.

Eni UHL Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

100.00

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

100.00

F.C.

Eni UKCS Ltd

London
(United Kingdom)

United
Kingdom

GBP

100

Eni UK 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.

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

F.C.

London
(United
Kingdom)

United
Kingdom

GBP

250,000,000

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.

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

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

100.00

F.C.

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.

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.

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.

London
(United
Kingdom)

United
Kingdom

GBP

200,010,000

Eni ULT Ltd

100.00

F.C.

Eni US Operating Co Inc

Dover,
Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni USA Gas Marketing Llc

Dover, Delaware
(USA)

USA

USD

10,000

Eni Marketing Inc

100.00

F.C.

Dover,
Delaware
(USA)

USA

USD

10,000

Eni Marketing Inc

100.00

F.C.

Eni USA Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Oil & Gas Inc

100.00

F.C.

Dover,
Delaware
(USA)

USA

USD

1,000

Eni Oil & Gas Inc

100.00

F.C.

Eni US Operating Co Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Venezuela BV

Amsterdam
(Netherlands)

Venezuela

EUR

20,000

Eni Venezuela E&P H

100.00

F.C.

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

963,800,000

Eni International BV
Eni Oil Holdings BV

99.99
(—)

100.00

F.C.

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.

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

F.C.

Amsterdam
(Netherlands)

Vietnam

EUR

20,000

Eni International BV

100.00

F.C.

Eni West Ganal Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni West Timor Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Yemen Ltd

London
(United Kingdom)

United
Kingdom

GBP

1,000

Burren Energy Plc

100.00

Eq.

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.

Algiers
(Algeria)

Algeria

DZD

1,000,000

Eni Algeria Ltd Sàrl

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-124~~F-125

TABLE OF CONTENTS

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(*)

First Calgary Petroleums LP

Wilmington
(USA)

Algeria

USD

Eni Canada Hold. Ltd
FCP Partner Co ULC

99.99
0.01

100.00

F.C.

Wilmington
(USA)

Algeria

USD

Eni Canada Hold. Ltd
FCP Partner Co ULC

99.99
0.01

100.00

F.C.

First Calgary
Petroleums Partner Co
ULC

Calgary
(Canada)

Canada

CAD

Eni Canada Hold. Ltd

100.00

F.C.

Calgary
(Canada)

Canada

CAD

Eni Canada Hold. Ltd

100.00

F.C.

Ieoc Exploration BV

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

F.C.

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

F.C.

Ieoc Production BV

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

F.C.

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.

Hamilton
(Bermuda)

Indonesia

USD

12,000

Eni Lasmo Plc

100.00

F.C.

Liverpool Bay Ltd

London
(United Kingdom)

United
Kingdom

USD

29,075,343

Eni ULX Ltd

100.00

F.C.

London
(United Kingdom)

United Kingdom

USD

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.

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.

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.

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.

Moscow
(Russia)

Russia

RUB

2,000,000

Eni Energy Russia BV
Eni Oil Holdings BV

99.90
0.10

100.00

F.C.

Tecnomare Egypt Ltd

Cairo
(Egypt)

Egypt

EGP

50,000

Tecnomare SpA
Eni SpA

99.00
1.00

Eq.

Zetah Congo Ltd

Nassau
(Bahamas)

Republic of
the Congo

USD

300

Eni Congo SA
Burren En.Congo Ltd

66.67
33.33

Co.

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.

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-125~~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
(former Eni Medio
Oriente SpA) San Donato
Milanese (MI) Italy EUR 6,655,992 Eni SpA 100.00 Co.
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
Eni Gas & Power NV 94.73
5.27 100.00 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.
Servizi Fondo Bombole
Metano SpA
Rome Italy EUR 13,580,000.20 Eni SpA 100.00 Co.
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 SpA
Third parties 51.00
49.00 51.00 F.C.
Distrigas LNG
Shipping SA
Bruxelles
(Belgium) Belgium EUR 788,579.55 LNG Shipping SpA
Eni Gas & Power NV 99.99
(—) 100.00 F.C.
Eni G&P France BV
Amsterdam
(Netherlands) France EUR 20,000 Eni International BV 100.00 100.00 F.C.
Eni G&P Trading BV
Amsterdam
(Netherlands) Turkey EUR 70,000 Eni International BV 100.00 100.00 F.C.
Eni Gas & Power
France SA
Levallois Perret
(France) France EUR 29,937,600 Eni G&P France BV
Third parties 99.87
0.13 99.87 F.C.
Eni Gas & Power NV
Vilvoorde
(Belgium) Belgium EUR 31,925,264 Eni SpA
Eni International BV 99.99
(—) 100.00 F.C.
Eni Trading &
Shipping Inc
Dover, Delaware
(USA) USA USD 36,000,000 Ets SpA 100.00 100.00 F.C.
Eni Wind Belgium NV
Vilvoorde
(Belgium) Belgium EUR 5,494,500 Eni Gas & Power NV
Eni International BV 99.77
0.23 100.00 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
Eni Gas & Power NV
Trans Tunis.P.Co SpA 99.85
0.05
0.05
0.05 100.00 F.C.
Tigáz Gepa Kft
(in liquidation)
Hajdúszoboszló
(Hungary) Hungary HUF 52,780,000 Tigáz Zrt 100.00 Eq.
Tigáz-Dso
Földgázelosztó kft Hajdúszoboszló
(Hungary) Hungary HUF 62,066,000 Tigáz Zrt 100.00 98.99 F.C.
Tigáz Tiszántúli Gázszolgáltató
Zártkörûen Mûködõ
Részvénytársaság Hajdúszoboszló
(Hungary) Hungary HUF 8,486,070,500 Eni SpA
Third parties 98.99
1.01 98.99 F.C.

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.

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

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

F.C.

LNG Shipping SpA

San Donato Milanese (MI)

Italy

EUR

240,900,000

Eni SpA

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

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

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

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

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

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~~F-127

TABLE OF CONTENTS

Refining & Marketing and Chemical

Refining & Marketing

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

In Italy
Consorzio AgipGas Sabina
(in liquidation)
Cittaducale (RI) Italy EUR 5,160 Eni Fuel SpA 100.00 Co.
Ecofuel SpA
San Donato
Milanese (MI) Italy EUR 52,000,000 Eni SpA 100.00 100.00 F.C.
Eni Fuel SpA
(former Eni Rete oil&nonoil SpA) Rome Italy EUR 58,944,310 Eni 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.
Outside Italy
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 Eq.
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
Third parties 99.99
(—) 100.00 F.C.
Eni USA R&M Co Inc Wilmington
(USA) USA USD 11,000,000 Eni International BV 100.00 100.00 F.C.
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.

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.

Eni Fuel SpA

Rome

Italy

EUR

58,944,310

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 USA R&M Co Inc

Wilmington

(USA)

USA

USD

11,000,000

Eni International BV

100.00

Eq.

Esacontrol SA

Quito

(Ecuador)

Ecuador

USD

60,000

Eni Ecuador SA

Third parties

87.00

13.00

Eq.

Esain SA

Quito

(Ecuador)

Ecuador

USD

30,000

Eni Ecuador SA

Tecnoesa SA

99.99

(..)

100.00

F.C.

Oléoduc du Rhône SA

Valais

(Switzerland)

Switzerland

CHF

7,000,000

Eni International BV

100.00

Eq.

OOO “Eni-Nefto”

Moscow

(Russia)

Russia

RUB

1,010,000

Eni International BV

Eni Oil Holdings BV

99.01

0.99

Eq.

Tecnoesa SA

Quito

(Ecuador)

Ecuador

USD

36,000

Eni Ecuador SA

Esain SA

99.99

(..)

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

~~F-127~~F-128

TABLE OF CONTENTS

Chemical

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

Versalis SpA San Donato
Milanese (MI) Italy EUR 1,364,790,000 Eni SpA 100.00 100.00 F.C.
In Italy
Consorzio Industriale Gas Naturale (in liquidation)
San Donato
Milanese (MI) Italy EUR 124,000 Versalis SpA
Raff. di Gela SpA
Eni SpA
Syndial SpA
Raff. Milazzo ScpA 53.55
18.74
15.37
0.76
11.58 Eq.
Outside Italy
Dunastyr Polisztirolgyártó Zártkoruen Mukodo 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.
Eni Chemicals
Trading (Shanghai)
Co Ltd
(in liquidation)
Shanghai
(China) China USD 5,000,000 Versalis SpA 100.00 Eq.
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
Congo) Republic of
Congo CDF 1,000,000 Versalis International
SA 100.00 Eq.
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 Pacific
(India) Private Ltd Mumbai
(India) India INR 238,700 Versalis Pacific
Trading
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 UK Ltd Lyndhurst,
Hampshire
(United Kingdom) United
Kingdom GBP 4,004,042 Versalis SpA 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

8,092,160,000

Versalis SpA

Versalis Deutsc.GmbH

Versalis Int.SA

96.34

1.83

100.00

F.C.

Versalis Americas Inc

Dover,
Delaware

(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

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

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.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

~~F-128~~F-129

TABLE OF CONTENTS

Corporate and ~~other~~Other activities

Corporate and financial companies

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(*)

In Italy

Agenzia Giornalistica
Italia SpA

Rome

Italy

EUR

2,000,000

Eni SpA

100.00

F.C.

Rome

Italy

EUR

2,000,000

Eni SpA

100.00

F.C.

Eni Adfin SpA

Rome

Italy

EUR

85,537,498.80

Eni SpA
Third parties

99.65
0.35

99.65

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

F.C.

San Donato
Milanese (MI)

Italy

EUR

3,360,000

Eni SpA

100.00

F.C.

EniServizi SpA

San Donato
Milanese (MI)

Italy

EUR

13,427,419.08

Eni SpA

100.00

F.C.

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 Adfin SpA
Third parties

49.00
51.00

48.83

F.C.

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.

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.

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

2,474,225,632

Eni International BV
Eni SpA

66.39
33.61

100.00

F.C.

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

F.C.

Dover,
Delaware

(USA)

USA

USD

15,000,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Insurance Designated Activity Company
(former Eni
Insurance Ltd)

Dublin
(Ireland)

Ireland

EUR

500,000,000

Eni SpA

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.

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.

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

F.C.

(*)

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~~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 Syndial SpA
Third parties 99.96
0.04 Eq.
Eni New Energy SpA San Donato
Milanese (MI) Italy EUR 5,000,000.00 Eni SpA 100.00 Co.
Industria Siciliana Acido
Fosforico - ISAF - SpA
(in liquidation)
Gela (CL) Italy EUR 1,300,000 Syndial SpA
Third parties 52.00
48.00 Eq.
Ing. Luigi Conti Vecchi SpA Assemini (CA) Italy EUR 5,518,620.64 Syndial SpA 100.00 100.00 F.C.
Syndial Servizi
Ambientali SpA
(former Syndial SpA –
Attività Diversificate) San Donato
Milanese (MI) Italy EUR 422,269,480.70 Eni SpA
Third parties 99.99
(—) 100.00 F.C.
Outside Italy
Oleodotto del Reno SA Coira
(Switzerland) Switzerland CHF 1,550,000 Syndial SpA 100.00 Eq.

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

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

F.C.

Outside Italy

Arm Wind Llp

Nur-Sultan
(Kazakhstan)

Kazakhstan

KZT

7,963,200,000

Windirect 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, 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

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~~F-131

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
Eni East Africa
SpA(†)
San Donato
Milanese (MI) Mozambique EUR 20,000,000 Eni SpA
Third parties 71.43
28.57 71.43 J.O.
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.
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 11,277,000,000 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 VEF 17,210,000 Eni Venezuela BV
Third parties 50.00
50.00 Eq.
Compañia Agua
Plana SA Caracas
(Venezuela) Venezuela VEF 100 Eni Venezuela BV
Third parties 26.00
74.00 Co.
East Delta
Gas Co 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 Company(†)
Cairo
(Egypt) Egypt EGP 20,000 Ieoc SpA
Third parties 50.00
50.00 Co.
El-Fayrouz
Petroleum Co(†)
(in liquidation)
Cairo
(Egypt) Egypt EGP 20,000 Ieoc Exploration BV
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.
Enstar Petroleum Ltd Calgary
(Canada) Canada CAD 0.10 Unimar Llc 100.00
Fedynskmorneftegaz
Sàrl(†)
Luxembourg
(Luxembourg) Russia USD 20,000 Eni Energy Russia BV
Third parties 33.33
66.67 Eq.
InAgip doo(†)
Zagreb
(Croatia) Croatia HRK 54,000 Eni Croatia 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.
Llc ‘Westgasinvest’(†)
Lviv
(Ukraine) Ukraine UAH 2,000,000 Eni Ukraine Hold.BV
Third parties 50.01
49.99 Eq.

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.

(*)

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-130~~F-132

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 ~~Company~~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

~~VEF~~VES

~~410,500,000~~3,790

Eni Lasmo Plc
Third parties

40.00
60.00

Eq.

PetroJunín SA(†)

Caracas
(Venezuela)

Venezuela

~~VEF~~VES

~~2,591,100,000~~24,021

Eni Lasmo Plc
Third parties

40.00
60.00

Eq.

PetroSucre SA

Caracas
(Venezuela)

Venezuela

~~VEF~~VES

~~220,300,000~~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

~~Eni East Africa~~Mozamb. Rov. V. SpA
Third parties

33.33
66.67

Co.

~~Shatskmorneftegaz Sàrl(†)~~

Rovuma LNG
Investments (DIFC) Ltd

~~Luxembourg~~Maputo
~~(Luxembourg)~~(Mozambique)

~~Russia~~Mozambique

USD

~~20,000~~50,000

Eni ~~Energy Russia~~Moz. LNG H. BV
Third parties

~~33.33~~25.00
~~66.67~~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

~~50.00~~25.00
~~50.00~~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.

~~Tapco Petrol Boru~~
~~Hatti~~
~~Sanayi ve Ticaret AS(†)~~

~~Istanbul~~
~~(Turkey)~~

~~Turkey~~

~~TRY~~

~~7,850,000~~

~~Eni International BV~~
~~Third parties~~

~~50.00~~
~~50.00~~

~~Eq.~~

Tecninco Engineering
Contractors Llp(†)

Aksai
(Kazakhstan)

Kazakhstan

KZT

29,478,455

~~Tecnomare~~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.

~~Unimar Llc(†)~~

~~Houston~~
~~(USA)~~

~~USA~~

~~USD~~

0(a)

~~Eni America Ltd~~
~~Third parties~~

~~50.00~~
~~50.00~~

~~Eq.~~

United Gas
Derivatives Co

New Cairo
(Egypt)

Egypt

USD

~~285,000,000~~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

~~1,315,912~~52,315,912

Eni Lasmo Plc
Third parties

50.00
50.00

Eq.

Virginia Indonesia
Co
CBM Ltd(†)

London
(United
Kingdom)

Indonesia

USD

~~631,640~~25,631,640

Eni Lasmo Plc
Third parties

50.00
50.00

Eq.

~~Virginia Indonesia Co~~
~~Llc~~

~~Wilmington~~
~~(USA)~~

~~Indonesia~~

~~USD~~

~~Unimar Llc~~

~~100.00~~

~~Virginia International~~
~~Co Llc~~

~~Wilmington~~
~~(USA)~~

~~Indonesia~~

~~USD~~

~~Unimar Llc~~

~~100.00~~

West Ashrafi
Petroleum Co(†)
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

50.00
50.00

~~Co.~~

~~Zetah Noumbi Ltd~~

~~Nassau~~
~~(Bahamas)~~

~~Republic of~~
~~the Congo~~

~~USD~~

~~100~~

~~Burren En.Congo Ltd~~
~~Third parties~~

~~37.00~~
~~63.00~~

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-131~~F-133

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
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 170,000,000 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
Blue Stream Pipeline
Co BV(†)
Amsterdam
(Netherlands) Russia USD 22,000 Eni International BV
Third parties 50.00
50.00 50.00 J.O.
Egyptian International Gas Technology Co Cairo
(Egypt) Egypt EGP 100,000,000 Eni International BV
Third parties 40.00
60.00 Co.
Gas Distribution Company of
Thessaloniki - Thessaly SA(†)
(former Eteria Parohis
Aeriou Thessalonikis AE)
Ampelokipi-
Menemeni
(Greece) Greece EUR 266,309,200 Eni 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.
Turul Gázvezeték Építõ es Vagyonkezelõ Részvénytársaság(†)
Tatabànya
(Hungary) Hungary HUF 404,000,000 Tigáz Zrt
Third parties 58.42
41.58 Eq.
Unión Fenosa Gas SA(†)
Madrid
(Spain) Spain EUR 32,772,000 Eni SpA
Third parties 50.00
50.00 Eq.

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.

(*)

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-134

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

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.

(*)

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-132~~F-135

TABLE OF CONTENTS

~~Refining & Marketing and Chemical~~Outside Italy

~~Refining & Marketing~~

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

In Italy
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 34.93
65.07 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.
PETRA SpA(†)
Ravenna Italy EUR 723,100 Ecofuel SpA
Third parties 50.00
50.00 Eq.
Petrolig Srl(†)
Genova Italy EUR 104,000 Ecofuel SpA
Third parties 70.00
30.00 70.00 J.O.
Petroven Srl(†)
Genova Italy EUR 156,000 Ecofuel SpA
Third parties 68.00
32.00 68.00 J.O.
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.
SeaPad SpA(†)
Genova Italy EUR 12,400,000 Ecofuel SpA
Third parties 80.00
20.00 Eq.
Seram SpA Fiumicino (RM) Italy EUR 852,000 Eni SpA
Third parties 25.00
75.00 Co.
Servizi Milazzo Srl(†)
Milazzo (ME) Italy EUR 100,000 Raff. Milazzo ScpA 100.00 50.00 J.O.
Sigea Sistema Integrato Genova Arquata SpA Genova Italy EUR 3,326,900 Ecofuel SpA
Third parties 35.00
65.00 Eq.
Termica Milazzo Srl(†)
Milazzo (ME) Italy EUR 100,000 Raff. Milazzo ScpA 100.00 50.00 J.O.

~~(*)~~

~~F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value~~

~~(†)~~

~~Jointly controlled entity.~~

~~F-133~~

~~TABLE OF CONTENTS~~

~~Refining & Marketing~~

Company name Registered
office Country of
operation Currency Share
Capital Shareholders %
Ownership % Equity
ratio
Consolidation
or valutation
method(*)

Outside Italy
AET - Raffineriebeteiligungs
gesellschaft mbH Schwedt
(Germany) Germany EUR 27,000 Eni Deutsch.GmbH
Third parties 33.33
66.67 Eq.
Bayernoil Raffineriegesellschaft mbH(†)
Vohburg
(Germany) Germany EUR 10,226,000 Eni Deutsch.GmbH
Third parties 20.00
80.00 20.00 J.O.
City Carburoil SA(†)
Rivera
(Switzerland) Switzerland CHF 6,000,000 Eni Suisse SA
Third parties 49.91
50.09 Eq.
ENEOS Italsing Pte Ltd Singapore
(Singapore) Singapore SGD 12,000,000 Eni International BV
Third parties 22.50
77.50 Eq.
FSH Flughafen Schwechat Hydranten-Gesellschaft OG Wien
(Austria) Austria EUR 7,098,752.57 Eni Market.A.GmbH
Eni Mineralölh.GmbH
Eni Austria GmbH
Third parties 14.29
14.29
14.28
57.14 Co.
Fuelling Aviation
Services GIE 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.
Routex BV Amsterdam
(Netherlands) Netherlands EUR 67,500 Eni International BV
Third parties 20.00
80.00 Eq.
Saraco SA Meyrin
(Switzerland) Switzerland CHF 420,000 Eni Suisse SA
Third parties 20.00
80.00 Co.
Supermetanol CA(†)
Jose Puerto
La Cruz
(Venezuela) Venezuela VEF 12,086,744.84 Ecofuel SpA
Supermetanol CA
Third parties
34.51(a)
30.07
35.42
50.00 J.O.
TBG Tanklager Betriebsgesellschaft GmbH(†)
Salzburg
(Austria) Austria EUR 43,603.70 Eni Market.A.GmbH
Third parties 50.00
50.00 Eq.
Weat Electronic Datenservice GmbH Düsseldorf
(Germany) Germany EUR 409,034 Eni Deutsch.GmbH
Third parties 20.00
80.00 Eq.

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Abu Dhabi Oil Refining Company (TAKREER)

Abu Dhabi
(United Arab
Emirates)

United Arab
Emirates

AED

500,000,000

Eni Abu Dhabi R&T BV
Third parties

20.00
80.00

Eq.

ADNOC Global Trading Ltd

Abu Dhabi
(United Arab
Emirates)

United Arab
Emirates

USD

1,000

Eni Abu Dhabi R&T BV
Third parties

20.00
80.00

Eq.

AET -
Raffinerie
beteiligungs
gesellschaft mbH(†)

Schwedt
(Germany)

Germany

EUR

27,000

Eni Deutsch.GmbH
Third parties

33.33
66.67

Eq.

Bayernoil Raffinerie
gesellschaft mbH(†)

Vohburg
(Germany)

Germany

EUR

10,226,000

Eni Deutsch.GmbH
Third parties

20.00
80.00

20.00

J.O.

City Carburoil SA(†)

Rivera
(Switzerland)

Switzerland

CHF

6,000,000

Eni Suisse SA
Third parties

49.91
50.09

Eq.

Egyptian International Gas Technology Co

Cairo
(Egypt)

Egypt

EGP

100,000,000

Eni International BV
Third parties

40.00
60.00

Co.

ENEOS Italsing Pte Ltd

Singapore
(Singapore)

Singapore

SGD

12,000,000

Eni International BV
Third parties

22.50
77.50

Eq.

Fuelling Aviation Services GIE

Tremblay en France
(France)

France

EUR

Eni France Sàrl
Third parties

25.00
75.00

Co.

Mediterranée Bitumes SA

Tunisi
(Tunisia)

Tunisia

TND

1,000,000

Eni International BV
Third parties

34.00
66.00

Eq.

Routex BV

Amsterdam
(Netherlands)

Netherlands

EUR

67,500

Eni International BV
Third parties

20.00
80.00

Eq.

Saraco SA

Meyrin

(Switzerland)

Switzerland

CHF

420,000

Eni Suisse SA
Third parties

20.00
80.00

Co.

Supermetanol CA(†)

Jose Puerto La Cruz
(Venezuela)

Venezuela

VES

120.867

Ecofuel SpA
Supermetanol CA
Third parties

34.51(a)
30.07
35.42

50.00

J.O.

TBG Tanklager Betriebs
gesellschaft GmbH(†)

Salzburg
(Austria)

Austria

EUR

43,603.70

Eni Market.A.GmbH
Third parties

50.00
50.00

Eq.

Weat Electronic Datenservice
GmbH

Düsseldorf
(Germany)

Germany

EUR

409,034

Eni Deutsch.GmbH
Third parties

20.00
80.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

(a)

Controlling interest:

Ecofuel SpA
Third parties

50.00
50.00

~~F-134~~F-136

TABLE OF CONTENTS

Chemical

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Brindisi Servizi Generali
Scarl

Brindisi

Italy

EUR

1,549,060

Versalis SpA
~~Syndial~~Eni Rewind SpA
EniPower SpA
Third parties

49.00
20.20
8.90
21.90

Eq.

IFM Ferrara ScpA

Ferrara

Italy

EUR

5,270,466

Versalis SpA
~~Syndial~~Eni Rewind SpA
S.E.F. Srl
Third parties

19.74
11.58
10.70
57.98

Eq.

Matrìca SpA(†)

Porto Torres (SS)

Italy

EUR

37,500,000

Versalis SpA
Third parties

50.00
50.00

~~Eq.~~

~~Newco Tech SpA(†)~~

~~Novara~~

~~Italy~~

~~EUR~~

~~500,000~~

~~Versalis SpA~~
~~Genomatica Inc.~~

~~80.00~~
~~20.00~~

Eq.

Novamont SpA

Novara

Italy

EUR

13,333,500

Versalis SpA
Third parties

25.00
75.00

Eq.

Priolo Servizi ScpA

Melilli (SR)

Italy

EUR

28,100,000

Versalis SpA
~~Syndial~~Eni Rewind SpA
Third parties

~~33.16~~33.11
~~4.38~~4.61
~~62.46~~62.28

Eq.

Ravenna Servizi
Industriali ScpA

Ravenna

Italy

EUR

5,597,400

Versalis SpA
EniPower SpA
Ecofuel SpA
Third parties

42.13
30.37
1.85
25.65

Eq.

Servizi Porto
Marghera Scarl

Porto Marghera
(VE)

Italy

EUR

8,695,718

Versalis SpA
~~Syndial~~Eni Rewind SpA
Third parties

48.44
38.39
13.17

Eq.

Outside Italy

Lotte Versalis Elastomers Co
Co Ltd(†)

Yeosu
(South Korea)

South Korea

KRW

~~192,000,010,000~~401,800,000,000

Versalis SpA
Third parties

50.00
50.00

Eq.

Versalis Zeal
Ltd (†)

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

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-135~~F-137

TABLE OF CONTENTS

Corporate and ~~other~~Other activities

~~Other activities~~Corporate and financial companies

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Outside Italy

Commonwealth Fusion
Systems Llc(a)

Wilmington
(USA)

USA

USD

115,000,519

Eni Next Llc
Third parties

Eq.

Form Energy Inc(b)

Sommerville
(USA)

USA

USD

50,889,548.24

Eni Next Llc
Third parties

Eq.

Other activities

In Italy

~~Filatura Tessile Nazionale~~
~~Italiana - FILTENI SpA~~
~~(in liquidation)~~

~~Ferrandina (MT)~~

~~Italy~~

~~EUR~~

~~4,644,000~~

~~Syndial SpA~~
~~Third parties~~

~~59.56(a)~~
~~40.44~~

~~Co.~~

Ottana Sviluppo ScpA
(in ~~liquidation)~~bankruptcy)

Nuoro

Italy

EUR

516,000

~~Syndial~~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~~(b)~~(c)
~~0.70~~1.46
~~68.76~~68.00

Eq.

Outside Italy

Ayla Energy Ltd(†)

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.

	~~(a)~~ ~~Controlling interest:~~			~~Syndial SpA~~ ~~Third parties~~			~~48.00~~ ~~52.00~~
	~~(b)~~(c) Controlling interest:			Eni SpA Third parties			~~30.76~~30.99 ~~69.24~~69.01

~~F-136~~F-138

TABLE OF CONTENTS

Other significant investments

Exploration & Production

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

~~% Equity~~
~~ratio~~

Consolidation
or valutation
method(*)

~~In Italy~~

Consorzio Universitario in Ingegneria per
la Qualità e l’Innovazione

Pisa

Italy

EUR

135,000

Eni SpA
Third parties

~~16.67~~20.00
~~83.33~~80.00

~~Co.~~F.V.

Outside Italy

~~Outside Italy~~

Administradora del Golfo de Paria
Este SA

Caracas
(Venezuela)

Venezuela

~~VEF~~VES

~~100~~0.001

Eni Venezuela BV
Third parties

19.50
80.50

~~Co.~~F.V.

Brass LNG Ltd

Lagos
(Nigeria)

Nigeria

USD

1,000,000

Eni Int. NA NV Sàrl
Third parties

20.48

79.52

~~Co.~~F.V.

Darwin LNG
Pty Ltd

West Perth
(Australia)

Australia

AUD

~~845,104,523.19~~367,278,503.01

Eni G&P LNG Aus. BV
Third parties

10.99

89.01

~~Co.~~F.V.

New Liberty Residential
Co Llc

West Trenton
(USA)

USA

USD

0(a)

Eni Oil & Gas Inc
Third parties

17.50
82.50

~~Co.~~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

~~Co.~~F.V.

~~Norsea Pipeline Ltd~~

~~Woking Surrey~~
~~(United~~
~~Kingdom)~~

~~United~~
~~Kingdom~~

~~GBP~~

~~7,614,062~~

~~Eni SpA~~
~~Third parties~~

~~10.32~~
~~89.68~~

~~Co.~~

North Caspian Operating Co
NV

Amsterdam
(Netherlands)

Kazakhstan

EUR

128,520

Agip Caspian Sea BV
Third parties

16.81

83.19

~~Co.~~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

~~Co.~~F.V.

Petrolera Güiria SA

Caracas
(Venezuela)

Venezuela

~~VEF~~VES

~~1,000,000~~10

Eni Venezuela BV
Third parties

19.50
80.50

~~Co.~~F.V.

~~Point Fortin LNG Exports Ltd~~

~~Port Of Spain~~
~~(Trinidad and~~
~~Tobago)~~

~~Trinidad and~~
~~Tobago~~

~~USD~~

~~10,000~~

~~Eni T&T Ltd~~
~~Third parties~~

~~17.31~~
~~82.69~~

~~Co.~~

SOMG - Sociedade de Operações e Manutenção de Gasodutos SA

Luanda
(Angola)

Angola

AOA

7,400,000

Eni Angola Prod.BV
Third parties

13.60

86.40

~~Co.~~F.V.

Torsina Oil Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

12.50

87.50

~~Co.~~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-137~~F-139

TABLE OF CONTENTS

Gas & Power

Outside Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

~~% Equity~~
~~ratio~~

Consolidation
or valutation
method(*)

~~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~~

~~Co.~~

Norsea Gas GmbH

Emden
(Germany)

Germany

EUR

1,533,875.64

Eni International BV
Third parties

13.04
86.96

~~Co.~~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

~~% Equity~~
~~ratio~~

Consolidation
or valutation
method(*)

~~In Italy~~

~~Consorzio Obbligatorio~~
~~degli Oli Usati~~

~~Rome~~

~~Italy~~

~~EUR~~

~~36,149~~

~~Eni SpA~~
~~Third parties~~

~~13.27~~
~~86.73~~

~~Co.~~

Società Italiana Oleodotti di
Gaeta SpA~~(1)~~(a)

Rome

Italy

ITL

360,000,000

Eni SpA
Third parties

72.48
27.52

F.V.

Outside Italy

Company name

~~Co.~~

~~Outside Italy~~Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

% Ownership

Consolidation
or valutation
method(*)

BFS Berlin Fuelling
Services GbR

Hamburg
(Germany)

Germany

EUR

~~145,758~~89,199

Eni Deutsch.GmbH
Third parties

12.50
87.50

~~Co.~~F.V.

Compania de Economia
Mixta ‘Austrogas’

Cuenca
(Ecuador)

Ecuador

USD

~~3,028,749~~5,665,329

Eni Ecuador SA
Third parties

~~13.31~~13.38
~~86.69~~86.62

~~Co.~~F.V.

Dé~~pot~~pôt Pétrolier de Fos
SA

Fos-Sur-Mer
(France)

France

EUR

3,954,196.40

Eni France Sàrl
Third parties

16.81
83.19

~~Co.~~F.V.

Dépôt Pétrolier de la
Côte
~~dAzur~~ d’Azur SAS

Nanterre
(France)

France

EUR

207,500

Eni France Sàrl
Third parties

18.00
82.00

~~Co.~~F.V.

Joint Inspection Group
Ltd

London
~~(United~~
(United Kingdom)

United
Kingdom

GBP

0(ab)

Eni SpA
Third parties

12.50
87.50

~~Co.~~F.V.

S.I.P.G. ~~Socé~~Société ~~Immobilier~~Immobilière Pé~~trolier~~trolière de Gestion Snc

~~Tremblay-En-~~
~~France~~Tremblay-En-France
(France)

France

EUR

40,000

Eni France Sàrl
Third parties

12.50
87.50

~~Co.~~F.V.

Sistema Integrado de Gestion
de Aceites Usados

Madrid
(Spain)

Spain

EUR

175,713

Eni Iberia SLU
Third parties

15.44
84.56

~~Co.~~F.V.

Tanklager - Gesellschaft Tegel (TGT) GbR

Hamburg
(Germany)

Germany

EUR

234,953

Eni Deutsch.GmbH
Third parties

12.50
87.50

~~Co.~~F.V.

TAR - Tankanlage
Ruemlang AG

Ruemlang
(Switzerland)

Switzerland

CHF

3,259,500

Eni Suisse SA
Third parties

16.27
83.73

~~Co.~~F.V.

Tema Lube Oil Co Ltd

Accra
(Ghana)

Ghana

GHS

258,309

Eni International BV
Third parties

12.00
88.00

~~Co.~~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.~~

~~(1)~~

Company under extraordinary administration procedure pursuant to ~~Law~~law no. 95 of ~~April~~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-138~~F-141

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~~

~~Emittenti Titoli SpA~~

~~Milan~~

~~Italy~~

~~EUR~~

~~4,264,000~~

~~Eni SpA~~
~~Emittenti Titoli SpA~~
~~Third parties~~

~~10.00~~ ~~(a)~~
~~0.78~~
~~89.22~~

~~Co.~~

~~Mip Politecnico di Milano - Graduate School of Business ScpA~~

~~Milan~~

~~Italy~~

~~EUR~~

~~150,000~~

~~Eni Corporate U.SpA~~
~~Third parties~~

~~10.67~~
~~89.33~~

~~Co.~~

~~(*)~~

~~F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value~~

~~(a)~~

~~Controlling interest:~~

~~Eni SpA~~
~~Third parties~~

~~10.08~~
~~89.92~~

Information on Eni’s consolidated subsidiaries with significant non-controlling interest

In ~~2016,~~2019 and 2018, Eni did not own any consolidated subsidiaries with a significant non-controlling interest. ~~In 2015, Eni did not own any consolidated subsidiaries with significant non-controlling~~

The total shareholders’ equity pertaining to minority interests as ~~consequence~~ of ~~the classification of the Saipem Group as discontinued operations.~~

~~Total shareholders’ equity attributable to non-controlling interests~~December 31, 2019, amounted to ~~€49~~€61 million (€~~1,916~~57 million at December 31, ~~2015, of which €1,872 million pertaining to the Saipem Group)~~2018).

Changes in the ownership interest without loss of control

In ~~2015 and 2016,~~2019, Eni acquired a 10% stake of Windirect BV. In 2018, Eni did not report any changes in ownership interest without loss or acquisition of control.

Principal joint ventures, joint operations and associates as of December 31, ~~2016~~2019

Company name

Registered office

Operating office

Business segment

% ownership
interest

% voting
rights

Registered office

Country of
operation

Business segment

% ownership
interest

Eni’s % of
the investment

Joint venture

CARDÓN IV SA

Caracas
(Venezuela)

Venezuela

Exploration &
Production

50.00

Gas Distribution Company of Thessaloniki - Thessaly SA

Ampelokipi-
Menemeni
(Greece)

Greece

Gas & Power

49.00

PetroJunín SA

Caracas
(Venezuela)

Venezuela

Exploration &
Production

40.00

Vår Energi AS

Forus
(Norway)

Norway

Exploration & Production

69.60

Saipem SpA

San Donato Milanese
(MI) (Italy)

Italia

Other Activities

30.54

30.76

San Donato Milanese
(MI) (Italy)

Italy

Other Activities

30.54

30.99

Unión Fenosa Gas SA

Madrid
(Spain)

Spain

Gas & Power

50.00

Madrid
(Spain)

Spain

Gas & Power

50.00

Cardón IV SA

Caracas
(Venezuela)

Venezuela

Exploration & Production

50.00

Gas Distribution Company of Thessaloniki - Thessaly SA

Ampelokipi-Menemeni
(Greece)

Greece

Gas & Power

49.00

Joint Operation

Mozambique Rovuma Venture SpA

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

Blue Stream Pipeline
Co BV

Amsterdam
(Netherlands)

Russia

Gas & Power

50.00

Amsterdam
(Netherlands)

Russia

Gas & Power

74.62

Eni East Africa SpA

San Donato Milanese
(MI) (Italy)

Mozambique

Exploration &
Production

71.43

Raffineria di Milazzo
ScpA

Milazzo
(ME) (Italy)

Italy

Refining &
Marketing

50.00

Associates

Abu Dhabi Oil Refining Co (Takreer)

Abu Dhabi
(United Arab Emirates)

United Arab
Emirates

Refining & Marketing

20.00

Angola LNG Ltd

Hamilton
(Bermuda)

Angola

Exploration &
Production

13.60

Hamilton
(Bermuda)

Angola

Exploration & Production

13.60

United Gas Derivatives Co

Cairo
(Egypt)

Egypt

Exploration &
Production

33.33

Coral FLNG SA

Maputo
(Mozambique)

Mozambique

Exploration & Production

25.00

~~F-139~~F-142

TABLE OF CONTENTS

~~The main~~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:

2015 2016
(€ million) CARDÓN
IV
SA Gas
Distribution
Company of
Thessaloniki
-Thessaly SA Petro
Junín
SA Unión
Fenosa
Gas
SA Other
joint
ventures Saipem
SpA CARDÓN
IV
SA Gas
Distribution
Company of
Thessaloniki
-Thessaly SA Petro
Junín
SA Unión
Fenosa
Gas
SA Other
joint
ventures
Current assets 1,125 61 197 695 326 7,783 451 34 336 651 209
- of which cash and cash equivalent 27 34 5 55 113 1,892 31 8 2 25 56
Non-current assets 2,951 204 623 1,156 1,086 6,500 3,628 285 703 1,037 886
Total assets 4,076 265 820 1,851 1,412 14,283 4,079 319 1,039 1,688 1,095
Current liabilities 3,356 19 361 294 705 5,668 455 13 480 232 469
- current financial
liabilities 2,223 55 496 206 61 299
Non-current liabilities 298 23 25 697 167 3,730 3,230 32 650 339
- non-current financial liabilities 590 76 3,194 2,108 547 281
Total liabilities 3,654 42 386 991 872 9,398 3,685 13 512 882 808
Net equity 422 223 434 860 540 4,885 394 306 527 806 287
Eni’s ownership
interest (%) 50.00 49.00 40.00 50.00 30.76 50.00 49.00 40.00 50.00
Book value of the investment 211 109 174 503 264 1,497 197 150 211 434 146
Revenues and other operating income 189 137 84 1,770 447 10,009 738 152 105 905 275
Operating expense (73) (92) (67) (1,739) (297) (9,100) (233) (98) (60) (921) (280)
Other operating
profit (loss) (5)
Depreciation, amortization and impairments (29) (14) (33) (137) (178) (2,408) (87) (22) (40) (131) (169)
Operating profit 87 31 (16) (106) (28) (1,499) 418 32 5 (147) (179)
Finance (expense) income (84) 107 (53) (5) (154) (206) 94 31 (19)
Income (expense) from investments 29 (7) 18 13
Profit before income taxes 3 31 91 (130) (40) (1,635) 212 32 99 (103) (198)
Income taxes (11) (9) (18) 31 1 (445) (252) (12) (24) 23 (20)
Net profit (8) 22 73 (99) (39) (2,080) (40) 20 75 (80) (218)
Other comprehensive income 44 30 25 26 48 12 18 29 (2)
Total other comprehensive
income 36 22 103 (74) (13) (2,032) (28) 20 93 (51) (220)
Net profit attributable
to Eni (4) 11 29 (74) (14) (144) (20) 10 30 (82) (125)
Dividends received by the joint venture 8 13 8 10 35


	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

~~F-140~~F-143

TABLE OF CONTENTS

~~The main~~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:


	2015								2016								2019
(€ million)	Angola LNG Ltd		PetroSucre SA		United Gas Derivatives Co		Other associates		Angola LNG Ltd		PetroSucre SA		United Gas Derivatives Co		Other associates		Abu Dhabi Oil Refining Co (TAKREER)		Angola LNG Ltd		Coral FLNG SA		Other associates
Current assets		111		950		329		215		507		1,119		253		219		4,659		890		241		838
- of which cash and cash equivalent		11		2		234		29		339		3		146		29		42		653		240		91
Non-current assets		8,092		618		126		417		8,376				140		569		18,868		9,952		4,119		3,259
Total assets		8,203		1,568		455		632		8,883		1,119		393		788		23,527		10,842		4,360		4,097
Current liabilities		498		1,013		101		165		284		1,049		41		183		8,470		185		230		585
- current financial liabilities								50								25		3,694						63
Non-current liabilities		215		81		14		130		1,863		70		1		200		912		2,135		3,722		2,677
- non-current financial liabilities								69		1,699						78		479		1,943		3,722		2,515
Total liabilities		713		1,094		115		295		2,147		1,119		42		383		9,382		2,320		3,952		3,262
Net equity		7,490		474		340		337		6,736				351		405		14,145		8,522		408		835
Eni’s ownership interest (%)		13.60		26.00		33.33				13.60		26.00		33.33
Eni’s % of the investment																		20.00		13.60		25.00
Book value of the investment		1,019		123		113		150		916				117		167		2,829		1,159		102		264
Revenues and other operating income				466		142		487		84		315		102		924
Revenues and other income																		399		1,552				818
Operating expense		(255)		(452)		(59)		(415)		(281)		(224)		(61)		(827)		(357)		(549)				(763)
Other operating profit (loss)																(2)
Depreciation, depletion, amortization and impairments		(3,180)		(197)		(28)		(36)		(188)		(568)		(13)		(57)
Depreciation, amortization and impairments																		(335)		(509)				(28)
Operating profit		(3,435)		(183)		55		36		(385)		(477)		28		38		(293)		494				27
Finance (expense) income		(10)		(11)		18		(4)		(70)		228		11		(4)
Finance income (expense)																		(46)		(151)		(12)		(2)
Income (expense) from investments								1										282						35
Profit before income taxes		(3,445)		(194)		73		33		(455)		(249)		39		34		(57)		343		(12)		60
Income taxes				(60)		(12)		(7)				(103)		5		(5)		11				5		(10)
Net profit		(3,445)		(254)		61		26		(455)		(352)		44		29		(46)		343		(7)		50
Other comprehensive income		992		71		35		9		200		(8)		11		1		(59)		162		8		5
Total other comprehensive income		(2,453)		(183)		96		35		(255)		(360)		55		30		(105)		505		1		55
Net profit attributable to Eni		(469)		(66)		20		3		(62)		(92)		14		4		(9)		47		(2)		22
Dividends received by the associate						21		1				30		14		9

Dividends received from the associate																		46						15

~~F-141~~F-144

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

F-145

TABLE OF CONTENTS

4938 Significant non-recurring events and operations

In ~~2014,~~2019, in ~~2015~~2018 and ~~2016,~~2017, Eni did not report any non-recurring events and operations.

5039 Positions or transactions deriving from atypical and/or unusual operations

In ~~2014, 2015~~2019, 2018 and ~~2016~~2017 no transactions deriving from atypical and/or unusual operations were reported.

5140 Subsequent events

NoImpact of COVID-19 and current trends in the oil market

The outbreak of a contagious disease known as COVID-19 which has spread rapidly 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.

We retain some levers of financial flexibility in case of a significant ~~events were reported after~~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, ~~2016.~~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.

~~F-142~~F-146

TABLE OF CONTENTS

Supplemental oil and gas information (unaudited)

The following information pursuant to “International Financial Reporting Standards” (IFRS) is presented in accordance with FASB Extractive Activities — Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs

Capitalized costs represent the total expenditures for proved and unproved mineral interests 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)
2015	Italy		Rest of Europe		North Africa*		*Egypt (of which)		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
(€ 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		15,280		15,110		26,904				35,241		3,364		10,424		16,156		2,037		124,516		17,643		6,747		15,512		20,691		43,272		12,118		11,434		15,912		1,360		144,689
Unproved property		18		297		444				2,443		1		1,229		874		203		5,509		18		323		502		34		2,361		11		1,592		979		194		6,014
Support equipment and facilities		355		42		1,758				1,318		112		34		74		15		3,708		384		21		1,549		225		1,328		116		36		23		12		3,694
Incomplete wells and other		1,114		3,501		2,280				4,932		8,900		1,665		729		123		23,244		635		103		1,362		359		2,541		1,165		1,006		457		43		7,671
Gross Capitalized Costs		16,767		18,950		31,386				43,934		12,377		13,352		17,833		2,378		156,977		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		(12,184)		(11,431)		(20,268)				(25,235)		(1,422)		(9,691)		(13,344)		(1,122)		(94,697)		(14,604)		(5,778)		(12,802)		(12,879)		(33,237)		(2,652)		(9,100)		(13,465)		(754)		(105,271)
Net Capitalized Costs consolidated subsidiaries(a)		4,583		7,519		11,118				18,699		10,955		3,661		4,489		1,256		62,280		4,076		1,416		6,123		8,430		16,265		10,758		4,968		3,906		855		56,797
Equity-accounted entities
Proved property				3		89				23				624		2,010				2,749				11,223		71				1,511				2		1,987				14,794
Unproved property				17										93						110				2,260										11						2,271
Support equipment and facilities						8										6				14				19		8										7				34
Incomplete wells and other				10		5				1,508				23		112				1,658				945		7				15				19		229				1,215
Gross Capitalized Costs				30		102				1,531				740		2,128				4,531				14,447		86				1,526				32		2,223				18,314
Accumulated depreciation, depletion and amortization				(23)		(77)				(441)				(628)		(338)				(1,507)				(5,287)		(61)				(323)				(20)		(1,124)				(6,815)
Net Capitalized Costs equity-accounted entities(a)				7		25				1,090				112		1,790				3,024
2016
Net Capitalized Costs equity-accounted entities (a)(c)																								9,160		25				1,203				12		1,099				11,499
2018
Consolidated subsidiaries
Proved property		15,951		18,678		28,754		15,262		38,539		10,790		11,680		17,127		2,085		143,604		16,569		6,236		14,140		17,474		40,607		11,240		12,711		15,347		1,967		136,291
Unproved property		18		301		471		55		2,461		1		1,155		903		210		5,520		18		332		456		56		2,311		3		1,530		861		193		5,760
Support equipment and facilities		357		42		1,830		203		1,375		111		37		77		15		3,844		369		21		1,516		208		1,281		108		38		52		12		3,605
Incomplete wells and other		724		242		4,175		1,828		5,117		2,565		2,248		317		134		15,522		653		103		1,554		1,504		2,307		1,382		562		595		127		8,787
Gross Capitalized Costs		17,050		19,263		35,230		17,348		47,492		13,467		15,120		18,424		2,444		168,490		17,609		6,692		17,666		19,242		46,506		12,733		14,841		16,855		2,299		154,443
Accumulated depreciation, depletion and amortization		(13,022)		(12,113)		(22,396)		(11,022)		(27,264)		(1,608)		(11,000)		(14,301)		(1,227)		(102,931)		(13,717)		(5,355)		(11,741)		(11,722)		(29,727)		(2,175)		(10,460)		(13,443)		(1,265)		(99,605)
Net Capitalized Costs consolidated subsidiaries(a)		4,028		7,150		12,834		6,326		20,228		11,859		4,120		4,123		1,217		65,559		3,892		1,337		5,925		7,520		16,779		10,558		4,381		3,412		1,034		54,838
Equity-accounted entities
Proved property				2		82				14				657		2,037				2,792				9,102		58				1,481				2		1,912				12,555
Unproved property				15										96						111				1,045										11						1,056
Support equipment and facilities						8										7				15				25		6										7				38
Incomplete wells and other				9		5				1,596				24		253				1,887				364		10				10				19		224				627
Gross Capitalized Costs				26		95				1,610				777		2,297				4,805				10,536		74				1,491				32		2,143				14,276
Accumulated depreciation, depletion and amortization				(20)		(72)				(482)				(682)		(602)				(1,858)				(4,543)		(54)				(266)				(19)		(1,052)				(5,934)
Net Capitalized Costs equity-accounted entities(a)				6		23				1,128				95		1,695				2,947

Net Capitalized Costs equity-accounted entities (a)(b)																								5,993		20				1,225				13		1,091				8,342

(a)

The amounts include net capitalized financial charges totalling ~~€1.029~~€878 million in ~~2015~~2019 and ~~€1.090~~€831 million in ~~2016~~2018 for the consolidates subsidiaries and ~~€92~~€166 million in ~~2015~~2019 and ~~€95~~€180 million in ~~2016~~2018 for equity-accounted entities.

(b)

Includes Vår Energi AS asset fair value.

(c)

~~F-143~~Includes allocation at fair value of the assets purchased by Vår Energi AS.

F-147

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)
2014 Italy Rest of
Europe North
Africa* *Egypt
(of which) Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration 29 188 227 635 160 139 20 1,398
Development(a)
1,382 2,395 955 3,479 572 1,118 1,169 122 11,192
Total costs incurred consolidated subsidiaries 1,411 2,583 1,182 4,114 572 1,278 1,308 142 12,590
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration 2 33 1 36
Development(b)
1 22 38 375 436
Total costs incurred equity-accounted entities 2 1 22 71 376 472
2015
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration 28 176 289 196 71 54 6 820
Development(a)
207 1,006 1,574 2,957 819 1,332 745 18 8,658
Total costs incurred consolidated subsidiaries 235 1,182 1,863 3,153 819 1,403 799 24 9,478
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration 1 14 1 16
Development(b)
1 1 112 35 554 703
Total costs incurred equity-accounted entities 2 1 112 49 555 719
2016
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions 2 2 2
Exploration 27 51 364 306 70 80 26 3 621
Development(a)
387 437 2,446 1,752 2,019 651 1,232 (5) 1 7,168
Total costs incurred consolidated subsidiaries
414 488 2,812 2,060 2,089 651 1,312 21 4 7,791
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration 1 13 14
Development(b)
1 28 12 95 136
Total costs incurred equity-accounted entities 1 1 28 25 95 150

(€ 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

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 ~~€2,062~~€2,069 million in ~~2014,~~2019, negative for ~~€817~~€517 million in ~~2015 and negative~~2018, asset for ~~€665~~€355 million in ~~2016.~~2017.

(b)

Includes the abandonment costs of the assets for €838 million in 2019, negative €22 million in 2018, negative for ~~€47~~€23 million in ~~2014, costs for €54 million in 2015 and negative for €15 million in 2016.~~2017.

(c)

Includes allocation at fair value of the assets purchased by Vår Energi AS.

F-148

TABLE OF CONTENTS

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 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.

~~F-144~~

~~TABLE OF CONTENTS~~

Results of operations from oil and gas producing activities by geographical area consist of the following:

2014
(€ million) Italy Rest of
Europe North
Africa Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Revenues:
- sales to consolidated entities 3,028 2,721 2,010 4,716 346 589 1,691 67 15,168
- sales to third parties 596 7,415 1,369 976 774 129 299 11,558
Total revenues 3,028 3,317 9,425 6,085 1,322 1,363 1,820 366 26,726
Operations costs (423) (687) (694) (935) (208) (223) (357) (124) (3,651)
Production taxes (293) (291) (648) (33) (15) (1,280)
Exploration expenses (36) (245) (72) (681) (204) (171) (69) (1,478)
D.D. & A. and Provision for abandonment(a) (819) (1,082) (1,330) (1,985) (90) (860) (1,295) (175) (7,636)
Other income (expenses) (184) (96) (773) (358) (251) (124) (78) (30) (1,894)
Pretax income from producing activities 1,273 1,207 6,265 1,478 773 (81) (81) (47) 10,787
Income taxes (503) (785) (3,992) (1,155) (291) (102) 29 43 (6,756)
Results of operations from E&P activities
of consolidated subsidiaries 770 422 2,273 323 482 (183) (52) (4) 4,031
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties 19 87 232 338
Total revenues 19 87 232 338
Operations costs (11) (11) (27) (49)
Production taxes (3) (94) (97)
Exploration expenses (1) (2) (31) (1) (35)
D.D. & A. and Provision for abandonment (1) (2) (40) (60) (103)
Other income (expenses) (1) 1 (32) (3) (41) (76)
Pretax income from producing activities (3) 2 (32) 2 9 (22)
Income taxes (2) (23) (18) (43)
Results of operations from E&P activities
of equity-accounted entities (3) (32) (21) (9) (65)

~~(a)~~

~~Includes asset impairments amounting to €851 million~~

~~F-145~~

~~TABLE OF CONTENTS~~

2015
(€ million) Italy Rest of
Europe North
Africa Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Revenues:
- sales to consolidated entities 2,124 1,828 1,403 3,514 231 628 1,118 29 10,875
- sales to third parties 501 5,681 914 659 854 131 226 8,966
Total revenues 2,124 2,329 7,084 4,428 890 1,482 1,249 255 19,841
Operations costs (403) (642) (948) (1,099) (239) (235) (453) (108) (4,127)
Production taxes (184) (240) (405) (30) (9) (868)
Exploration expenses (35) (205) (164) (216) (210) (35) (6) (871)
D.D. & A. and Provision for abandonment(a) (750) (2,022) (2,938) (3,835) (109) (1,491) (1,775) (111) (13,031)
Other income (expenses) (215) (142) (564) (290) (156) (282) (9) (23) (1,681)
Pretax income from producing
activities 537 (682) 2,230 (1,417) 386 (766) (1,023) (2) (737)
Income taxes (182) 589 (2,148) 272 (142) 90 406 (25) (1,140)
Results of operations from E&P activities
of consolidated subsidiaries 355 (93) 82 (1,145) 244 (676) (617) (27) (1,877)
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties 19 68 248 335
Total revenues 19 68 248 335
Operations costs (9) (13) (49) (71)
Production taxes (3) (82) (85)
Exploration expenses (16) (16)
D.D. & A. and Provision for abandonment (1) (3) (432) (77) (78) (591)
Other income (expenses) (3) (1) (35) (6) (48) (93)
Pretax income from producing
activities (4) 3 (467) (44) (9) (521)
Income taxes (3) 8 (29) (24)
Results of operations from E&P activities
of equity-accounted entities (4) (467) (36) (38) (545)

~~(a)~~

~~Includes asset impairments amounting to €5,051 million~~

~~F-146~~

~~TABLE OF CONTENTS~~

2016 (€ million)	Italy		Rest of Europe		North Africa*		*Egypt (of which)		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
(€ 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		1,217		1,673		941		9		3,178		252		1,027		833		4		9,125		1,493		618		1,081				4,576			1,195		2,367		825		5		12,160
- sales to third parties				432		4,312		1,471		485		606		114		102		165		6,216				30		4,084		3,715		944			766		149		180		227		10,095
Total revenues		1,217		2,105		5,253		1,480		3,663		858		1,141		935		169		15,341		1,493		648		5,165		3,715		5,520			1,961		2,516		1,005		232		22,255
Operations costs		(311)		(599)		(807)		(356)		(968)		(269)		(215)		(325)		(49)		(3,543)
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		(96)				(176)				(282)				(17)				(5)		(576)		(183)				(263)				(483)					(252)		(7)		(6)		(1,194)
Exploration expenses		(35)		(40)		(87)		(42)		(142)				(39)		(28)		(3)		(374)		(25)		(51)		(30)		(10)		(90)			(39)		(170)		(31)		(43)		(489)
D.D. & A. and Provision for abandonment(a)		(923)		(943)		(1,366)		(691)		(1,093)		(129)		(952)		(480)		(67)		(5,953)		(944)		(201)		(839)		(978)		(3,060)			(444)		(820)		(607)		(97)		(7,990)
Other income (expenses)		(342)		(232)		(466)		(265)		(917)		(57)		(130)		(120)		(8)		(2,272)		(337)		(16)		(452)		(433)		(502)			(71)		(76)		(86)		(1)		(1,974)
Pretax income from producing activities		(490)		291		2,351		126		261		403		(212)		(18)		37		2,623		(392)		168		3,001		1,954		499			994		938		(14)		42		7,190
Income taxes		159		(1)		(1,707)		(89)		97		(139)		32		(9)		(9)		(1,577)		148		(11)		(2,561)		(839)		(268)			(326)		(719)		(5)		(31)		(4,612)
Results of operations from E&P activities of consolidated subsidiaries		(331)		290		644		37		358		264		(180)		(27)		28		1,046
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						15								36		493				544				677		15				207							315				1,214
Total revenues						15								36		493				544				1,757		15				207							315				2,294
Operations costs						(9)								(10)		(54)				(73)
Production costs																								(336)		(8)				(24)							(25)				(393)
Transportation costs																								(84)		(1)				(11)											(96)
Production taxes						(3)										(121)				(124)						(2)				(7)							(81)				(90)
Exploration expenses														(13)						(13)				(47)																	(47)
D.D. & A. and Provision for abandonment						(1)				(26)				(32)		(240)				(299)				(722)		(1)				(70)							(51)				(844)
Other income (expenses)				(3)		(1)				(26)				(16)		(25)				(71)				(237)		(1)				(28)					(3)		(133)				(402)
Pretax income from producing activities				(3)		1				(52)				(35)		53				(36)				331		2				67	��				(3)		25				422
Income taxes						(2)								(6)		(162)				(170)				(179)		(2)											(54)				(235)
Results of operations from E&P activities of equity-accounted entities				(3)		(1)				(52)				(41)		(109)				(206)				152						67					(3)		(29)				187

(a)

Includes asset net ~~(reversal)~~impairment amounting to ~~€700~~€1,217 million

(b)

Results of operations exclude revenues, DD&A and income taxes associated with 3,8 million boe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause. The price collected by the buyer has been recognized as revenues in the segment information of the E&P sector prepared in accordance with IFRS and DD&A and income taxes have been accrued accordingly, because the Group performance obligation under the contract has been fulfilled and it is very likely that the buyer will not redeem its contractual right to lift within the contractual terms.

F-149

TABLE OF CONTENTS

(€ million) 2018	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		2,120		2,740		1,277				4,701		1,140		1,902		934		4		14,818
- sales to third parties				494		3,741		3,207		830		769		493		50		190		9,774
Total revenues		2,120		3,234		5,018		3,207		5,531		1,909		2,395		984		194		24,592
Production costs		(402)		(488)		(363)		(343)		(974)		(269)		(220)		(234)		(48)		(3,341)
Transportation costs		(8)		(142)		(50)		(11)		(42)		(136)		(7)		(16)				(412)
Production taxes		(171)				(243)				(435)				(191)				(6)		(1,046)
Exploration expenses		(25)		(85)		(48)		(22)		(44)		(3)		(79)		(69)		(5)		(380)
D.D. & A. and Provision for abandonment(a)		(281)		(664)		(582)		(795)		(2,490)		(387)		(941)		(594)		(67)		(6,801)
Other income (expenses)		(442)		(193)		(101)		(239)		(1,126)		(67)		(135)		(54)				(2,357)
Pretax income from producing activities		791		1,662		3,631		1,797		420		1,047		822		17		68		10,255
Income taxes		(170)		(1,070)		(2,494)		(542)		(264)		(308)		(678)		7		(26)		(5,545)
Results of operations from E&P activities of consolidated subsidiaries		621		592		1,137		1,255		156		739		144		24		42		4,710
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties						15				257				6		420				698
Total revenues						15				257				6		420				698
Production costs						(7)				(34)				(2)		(36)				(79)
Transportation costs						(1)				(28)						(2)				(31)
Production taxes						(3)				(26)						(114)				(143)
Exploration expenses				(6)										(235)						(241)
D.D. & A. and Provision for abandonment						(1)				224				(3)		(222)				(2)
Other income (expenses)				(1)		2				(27)				(25)		(122)				(173)
Pretax income from producing activities				(7)		5				366				(259)		(76)				29
Income taxes						(3)								(2)		(35)				(40)
Results of operations from E&P activities of equity-accounted entities				(7)		2				366				(261)		(111)				(11)

(a)

Includes asset net impairment amounting to €726 million

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(€ million) 2017	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		1,619		1,897		1,056				3,888		681		911			932		3		10,987
- sales to third parties				481		3,184		2,128		547		713		291			96		168		7,608
Total revenues		1,619		2,378		4,240		2,128		4,435		1,394		1,202			1,028		171		18,595
Production costs		(332)		(523)		(455)		(303)		(952)		(271)		(202)			(258)		(48)		(3,344)
Transportation costs		(5)		(164)		(49)		(11)		(34)		(125)		(4)			(54)				(446)
Production taxes		(130)				(200)				(331)				(11)					(5)		(677)
Exploration expenses		(26)		(122)		(22)		(191)		(60)				(61)			(39)		(4)		(525)
D.D. & A. and Provision for abandonment(a)		(465)		(838)		(679)		(767)		(2,063)		(289)		(765)			(577)		(59)		(6,502)
Other income (expenses)		1,563		(141)		(162)		690		(716)		(221)		(84)			(342)		2		589
Pretax income from producing activities		2,224		590		2,673		1,546		279		488		75			(242)		57		7,690
Income taxes		(299)		(216)		(1,978)		(214)		(38)		(223)		(67)			(38)		(23)		(3,096)
Results of operations from E&P activities of consolidated subsidiaries		1,925		374		695		1,332		241		265		8			(280)		34		4,594
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties						14				129				22			517				682
Total revenues						14				129				22			517				682
Production costs						(6)				(19)				(9)			(39)				(73)
Transportation costs						(2)				(18)							(1)				(21)
Production taxes						(2)				(8)							(146)				(156)
Exploration expenses				(1)										(13)							(14)
D.D. & A. and Provision for abandonment						(1)				(54)				(13)			(271)				(339)
Other income (expenses)				(2)		(2)				26				3	��		(199)				(174)
Pretax income from producing activities				(3)		1				56				(10)			(139)				(95)
Income taxes						(1)								(4)			(20)				(25)
Results of operations from E&P activities of equity-accounted entities				(3)						56				(14)			(159)				(120)

(a)

Includes asset net reversal amounting to €158 million

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Oil and natural gas reserves

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow 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 ~~geo-scientific~~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~~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 ~~2016,~~2019, the average price for the marker Brent crude oil was ~~$42.8~~$63 per barrel.

~~F-147~~

~~TABLE OF CONTENTS~~

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.

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 ~~2016,~~2019, Ryder Scott Company, ~~and~~ DeGolyer and MacNaughton ~~and Gaffney, Cline & Associates~~21 provided an independent evaluation of about ~~41%~~31% of Eni’s total proved reserves as of December 31, ~~2016~~20192241, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.

In the three-year period from ~~2014~~2017 to ~~2016, 94%~~2019, 86% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, ~~2016,~~2019, the principal ~~properties~~property not subjected to independent evaluation in the last three years ~~are Zubair (Iraq), Bu Attifel (Libya), and Cafc-Mle (Algeria).~~was Zohr.

Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented ~~50%~~57%, ~~52%~~61% and ~~59%~~60% of total proved reserves as of December 31, ~~2014, 2015~~2019, 2018 and ~~2016,~~2017, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service ~~and “buy-back”~~ contracts; proved reserves associated with such contracts represented 3%, 5%3% and 5%4% of total proved reserves on an oil-equivalent basis as of December 31, ~~2014, 2015~~2019, 2018 and ~~2016,~~2017, respectively.

From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018 and independent evaluation was provided also by Societé Generale de Surveillance (SGS).

See “Item 19 – Exhibits”.

Including reserves of equity-accounted investments.

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Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent ~~0,6%~~4%, ~~0,6%~~4% and ~~1,8%~~1.6% of total proved reserves as of December 31, ~~2014, 2015~~2019, 2018 and ~~2016,~~2017, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant.

Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.

~~From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott, from 2015 also Gaffney, Cline & Associates.~~

~~The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2016.~~

~~Including reserves of equity-accounted entities.~~

~~F-148~~

~~TABLE OF CONTENTS~~

The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, ~~2014, 2015~~2019, 2018 and ~~2016.~~2017.

~~Crude~~CRUDE OIL (INCLUDING CONDENSATE AND NATURAL GAS LIQUIDS)

(million barrels)
2019	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2018		208		48		493		279		718		704		476		252		5		3,183
of which: developed		156		44		317		153		551		587		252		143		5		2,208
undeveloped		52		4		176		126		167		117		224		109				975
Purchase of Minerals in Place																29				29
Revisions of Previous Estimates		5		1		37		10		46		79		45		(16)		(4)		203
Improved Recovery
Extensions and Discoveries								2		21				2		9				34
Production		(19)		(8)		(62)		(27)		(90)		(37)		(32)		(20)				(295)
Sales of Minerals in Place(a)										(1)						(29)				(30)
Reserves at December 31, 2019		194		41		468		264		694		746		491		225		1		3,124
Equity-accounted entities
Reserves at December 31, 2018				297		11				12						37				357
of which: developed				154		11				8						32				205
undeveloped				143						4						5				152
Purchase of Minerals in Place				109																109
Revisions of Previous Estimates				45		2										(5)				42
Improved Recovery
Extensions and Discoveries				6																6
Production				(27)		(1)				(2)						(1)				(31)
Sales of Minerals in Place				(6)																(6)
Reserves at December 31, 2019				424		12				10						31				477
Reserves at December 31, 2019		194		465		480		264		704		746		491		256		1		3,601
Developed		137		256		313		149		526		682		245		179		1		2,488
consolidated subsidiaries		137		37		301		149		519		682		245		148		1		2,219
equity-accounted entities				219		12				7						31				269
Undeveloped		57		209		167		115		178		64		246		77				1,113
consolidated subsidiaries		57		4		167		115		175		64		246		77				905
equity-accounted entities				205						3										208

(a)

Includes 0.6 Mboe as part of a long-term supply agreement to a state-owned national oil ~~(Including Condensate and Natural Gas Liquids)~~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.

(million barrels)
2014 Italy Rest of
Europe North
Africa Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Reserves at December 31, 2013 220 330 830 723 679 128 147 22 3,079
of which: developed 177 179 561 465 295 38 96 20 1,831
undeveloped 43 151 269 258 384 90 51 2 1,248
Purchase of Minerals in Place 1 1
Revisions of Previous Estimates 49 35 32 70 35 16 22 (7) 252
Improved Recovery 3 1 2 6
Extensions and Discoveries 1 2 36 5 44
Production (27) (34) (91) (84) (19) (13) (27) (2) (297)
Sales of Minerals in Place (1) (7) (8)
Reserves at December 31, 2014 243 331 776 739 697 131 147 13 3,077
Equity-accounted entities
Reserves at December 31, 2013 16 15 1 116 148
of which: developed 16 19 35
undeveloped 15 1 97 113
Purchase of Minerals in Place
Revisions of Previous Estimates (1) 3 5 7
Improved Recovery
Extensions and Discoveries
Production (1) (1) (4) (6)
Sales of Minerals in Place
Reserves at December 31, 2014 14 17 1 117 149
Reserves at December 31, 2014 243 331 790 756 697 132 264 13 3,226
Developed 184 174 534 477 306 64 142 12 1,893
consolidated subsidiaries 184 174 521 470 306 64 116 12 1,847
equity-accounted entities 13 7 26 46
Undeveloped 59 157 256 279 391 68 122 1 1,333
consolidated subsidiaries 59 157 255 269 391 67 31 1 1,230
equity-accounted entities 1 10 1 91 103

2015 Italy Rest of
Europe North
Africa Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Reserves at December 31, 2014 243 331 776 739 697 131 147 13 3,077
of which: developed 184 174 521 470 306 64 116 12 1,847
undeveloped 59 157 255 269 391 67 31 1 1,230
Purchase of Minerals in Place
Revisions of Previous Estimates 10 5 139 143 94 159 64 (2) 612
Improved Recovery 2 2
Extensions and Discoveries 2 14 6 22
Production (25) (31) (98) (93) (20) (28) (28) (2) (325)
Sales of Minerals in Place (16) (16)
Reserves at December 31, 2015 228 305 821 787 771 262 189 9 3,372
Equity-accounted entities
Reserves at December 31, 2014 14 17 1 117 149
of which: developed 13 7 26 46
undeveloped 1 10 1 91 103
Purchase of Minerals in Place
Revisions of Previous Estimates (1) 45 44
Improved Recovery
Extensions and Discoveries
Production (1) (1) (4) (6)
Sales of Minerals in Place
Reserves at December 31, 2015 13 16 158 187
Reserves at December 31, 2015 228 305 834 803 771 262 347 9 3,559
Developed 171 237 555 517 355 126 178 9 2,148
consolidated subsidiaries 171 237 542 511 355 126 149 9 2,100
equity-accounted entities 13 6 29 48
Undeveloped 57 68 279 286 416 136 169 1,411
consolidated subsidiaries 57 68 279 276 416 136 40 1,272
equity-accounted entities 10 129 139

~~F-149~~F-153

TABLE OF CONTENTS

2018	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2017		215		360		476		280		764		766		232		162		7		3,262
of which: developed		169		219		306		203		546		547		81		144		5		2,220
undeveloped		46		141		170		77		218		219		151		18		2		1,042
Purchase of Minerals in Place														319						319
Revisions of Previous Estimates		15		6		73		21		30		(27)		(54)		23		(1)		86
Improved Recovery								7						6						13
Extensions and Discoveries										13				1		86				100
Production		(22)		(40)		(56)		(28)		(89)		(35)		(28)		(19)		(1)		(318)
Sales of Minerals in Place				(278)				(1)												(279)
Reserves at December 31, 2018		208		48		493		279		718		704		476		252		5		3,183
Equity-accounted entities
Reserves at December 31, 2017						12				12						136				160
of which: developed						12				6						25				43
undeveloped										6						111				117
Purchase of Minerals in Place				297																297
Revisions of Previous Estimates										1						(96)				(95)
Improved Recovery
Extensions and Discoveries
Production						(1)				(1)						(3)				(5)
Sales of Minerals in Place
Reserves at December 31, 2018				297		11				12						37				357
Reserves at December 31, 2018		208		345		504		279		730		704		476		289		5		3,540
Developed		156		198		328		153		559		587		252		175		5		2,413
consolidated subsidiaries		156		44		317		153		551		587		252		143		5		2,208
equity-accounted entities				154		11				8						32				205
Undeveloped		52		147		176		126		171		117		224		114				1,127
consolidated subsidiaries		52		4		176		126		167		117		224		109				975
equity-accounted entities				143						4						5				152

2017	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, 2016		176		264		454		281		809		767		307		163		9		3,230
of which: developed		132		228		287		205		507		556		124		143		8		2,190
undeveloped		44		36		167		76		302		211		183		20		1		1,040
Purchase of Minerals in Place										2										2
Revisions of Previous Estimates		59		29		73		21		31		29		(69)		19		(1)		191
Improved Recovery				1		6		7						9						23
Extensions and Discoveries				103		1				18				4		3				129
Production		(20)		(37)		(58)		(26)		(90)		(30)		(19)		(23)		(1)		(304)
Sales of Minerals in Place								(3)		(6)										(9)
Reserves at December 31, 2017		215		360		476		280		764		766		232		162		7		3,262
Equity-accounted entities
Reserves at December 31, 2016						13				15						140				168
of which: developed						13				8						22				43
undeveloped										7						118				125
Purchase of Minerals in Place
Revisions of Previous Estimates										(2)						1				(1)
Improved Recovery
Extensions and Discoveries
Production						(1)				(1)						(5)				(7)
Sales of Minerals in Place
Reserves at December 31, 2017						12				12						136				160
Reserves at December 31, 2017		215		360		488		280		776		766		232		298		7		3,422
Developed		169		219		318		203		552		547		81		169		5		2,263
consolidated subsidiaries		169		219		306		203		546		547		81		144		5		2,220
equity-accounted entities						12				6						25				43
Undeveloped		46		141		170		77		224		219		151		129		2		1,159
consolidated subsidiaries		46		141		170		77		218		219		151		18		2		1,042
equity-accounted entities										6						111				117

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TABLE OF CONTENTS

~~Crude~~NATURAL GAS

(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

(a)

Includes 17.6 BCF as part of a long-term supply agreement to a state-owned national oil ~~(Including Condensate and Natural Gas Liquids)~~ ~~continued~~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.

(million barrels)
2016 Italy Rest of
Europe North
Africa* *Egypt
(of which) Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Reserves at December 31, 2015 228 305 821 327 787 771 262 189 9 3,372
of which: developed 171 237 542 230 511 355 126 149 9 2,100
undeveloped 57 68 279 97 276 416 136 40 1,272
Purchase of Minerals in Place
Revisions of Previous Estimates (35) (4) (7) (26) 113 20 73 (1) 1 160
Improved Recovery 1 1 2
Extensions and Discoveries 2 9 8 11
Production (17) (40) (89) (28) (91) (24) (28) (25) (1) (315)
Sales of Minerals in Place
Reserves at December 31, 2016 176 264 735 281 809 767 307 163 9 3,230
Equity-accounted entities
Reserves at December 31, 2015 13 16 158 187
of which: developed 13 6 29 48
undeveloped 10 129 139
Purchase of Minerals in Place
Revisions of Previous Estimates 1 (1) (13) (13)
Improved Recovery
Extensions and Discoveries
Production (1) (5) (6)
Sales of Minerals in Place
Reserves at December 31, 2016 13 15 140 168
Reserves at December 31, 2016 176 264 748 281 824 767 307 303 9 3,398
Developed 132 228 505 205 515 556 124 165 8 2,233
consolidated subsidiaries 132 228 492 205 507 556 124 143 8 2,190
equity-accounted entities 13 8 22 43
Undeveloped 44 36 243 76 309 211 183 138 1 1,165
consolidated subsidiaries 44 36 243 76 302 211 183 20 1 1,040
equity-accounted entities 7 118 125

~~Natural Gas(a)~~

(billion cubic feet)
2014	Italy		Rest of Europe		North Africa		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
2018																			Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2013		1,532		1,247		5,231		2,374		1,957		744		509		848		14,442
Reserves at December 31, 2017																				1,131		896		3,145		4,351		3,660		2,108		1,065		225		709		17,290
of which: developed		1,266		904		2,432		1,295		1,488		286		310		561		8,542		987		771		1,233		1,421		1,693		1,878		862		171		519		9,535
undeveloped		266		343		2,799		1,079		469		458		199		287		5,900		144		125		1,912		2,930		1,967		230		203		54		190		7,755
Purchase of Minerals in Place				21														21														69						69
Revisions of Previous Estimates		113		99		668		214		165		156		23		(1)		1,437		138		50		219		2,238		23		(22)		81		45		(16)		2,756
Improved Recovery
Extensions and Discoveries						19		341				59		16				435		86								7				205		76				374
Production		(213)		(195)		(627)		(185)		(73)		(113)		(80)		(40)		(1,526)		(156)		(162)		(474)		(445)		(184)		(97)		(201)		(43)		(42)		(1,804)
Sales of Minerals in Place				(1)														(1)				(464)				(869)						(2)		(26)				(1,361)
Reserves at December 31, 2014		1,432		1,171		5,291		2,744		2,049		846		468		807		14,808
Reserves at December 31, 2018																				1,199		320		2,890		5,275		3,506		1,989		1,217		277		651		17,324
Equity-accounted entities
Reserves at December 31, 2013						15		330				28		3,353				3,726
Reserves at December 31, 2017																								14				349						1,819				2,182
of which: developed						15						14		5				34						14				83						1,819				1,916
undeveloped								330				14		3,348				3,692										266										266
Purchase of Minerals in Place																						360																360
Revisions of Previous Estimates						2		25				(2)						25						2				(6)						(22)				(26)
Improved Recovery
Extensions and Discoveries
Production						(2)		(4)				(8)						(14)						(2)				(33)						(81)				(116)
Sales of Minerals in Place
Reserves at December 31, 2014						15		351				18		3,353				3,737
Reserves at December 31, 2014		1,432		1,171		5,306		3,095		2,049		864		3,821		807		18,545
Reserves at December 31, 2018																						360		14				310						1,716				2,400
Reserves at December 31, 2018																				1,199		680		2,904		5,275		3,816		1,989		1,217		1,993		651		19,724
Developed		1,192		887		2,125		1,360		1,553		271		399		675		8,462		980		576		1,461		3,331		1,928		1,846		822		1,870		452		13,266
consolidated subsidiaries		1,192		887		2,110		1,271		1,553		261		393		675		8,342		980		300		1,447		3,331		1,871		1,846		822		154		452		11,203
equity-accounted entities						15		89				10		6				120				276		14				57						1,716				2,063
Undeveloped		240		284		3,181		1,735		496		593		3,422		132		10,083		219		104		1,443		1,944		1,888		143		395		123		199		6,458
consolidated subsidiaries		240		284		3,181		1,473		496		585		75		132		6,466		219		20		1,443		1,944		1,635		143		395		123		199		6,121
equity-accounted entities								262				8		3,347				3,617				84						253										337

~~F-150~~F-155

TABLE OF CONTENTS

~~Natural Gas(a)~~ ~~continued~~

(billion cubic feet)
2015 Italy Rest of
Europe North
Africa Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Reserves at December 31, 2014 1,432 1,171 5,291 2,744 2,049 846 468 807 14,808
of which: developed 1,192 887 2,110 1,271 1,553 261 393 675 8,342
undeveloped 240 284 3,181 1,473 496 585 75 132 6,466
Purchase of Minerals in Place
Revisions of Previous Estimates 68 74 163 145 385 24 69 5 933
Improved Recovery
Extensions and Discoveries 4 124 114 242
Production (200) (201) (780) (171) (80) (106) (94) (41) (1,673)
Sales of Minerals in Place (4) (4) (8)
Reserves at December 31, 2015 1,304 1,044 4,798 2,714 2,354 878 439 771 14,302
Equity-accounted entities
Reserves at December 31, 2014 15 351 18 3,353 3,737
of which: developed 15 89 10 6 120
undeveloped 262 8 3,347 3,617
Purchase of Minerals in Place
Revisions of Previous Estimates 36 3 253 292
Improved Recovery
Extensions and Discoveries
Production (2) (9) (25) (36)
Sales of Minerals in Place
Reserves at December 31, 2015 13 387 12 3,581 3,993
Reserves at December 31, 2015 1,304 1,044 4,811 3,101 2,354 890 4,020 771 18,295
Developed 1,051 919 2,579 1,475 1,830 194 1,668 585 10,301
consolidated subsidiaries 1,051 919 2,566 1,390 1,830 185 373 585 8,899
equity-accounted entities 13 85 9 1,295 1,402
Undeveloped 253 125 2,232 1,626 524 696 2,352 186 7,994
consolidated subsidiaries 253 125 2,232 1,324 524 693 �� 66 186 5,403
equity-accounted entities 302 3 2,286 2,591

2016 Italy Rest of
Europe North
Africa* *Egypt
(of which) Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
Consolidated subsidiaries
Reserves at December 31, 2015 1,304 1,044 4,798 947 2,714 2,354 878 439 771 14,302
of which: developed 1,051 919 2,566 822 1,390 1,830 185 373 585 8,899
undeveloped 253 125 2,232 125 1,324 524 693 66 186 5,403
Purchase of Minerals in Place
Revisions of Previous Estimates (155) 18 496 25 223 224 200 8 12 1,026
Improved Recovery
Extensions and Discoveries 4,767 4,767 15 4,782
Production (172) (184) (803) (219) (170) (93) (90) (94) (42) (1,648)
Sales of Minerals in Place
Reserves at December 31, 2016 977 878 9,258 5,520 2,767 2,485 1,003 353 741 18,462
Equity-accounted entities
Reserves at December 31, 2015 13 387 12 3,581 3,993
of which: developed 13 85 9 1,295 1,402
undeveloped 302 3 2,286 2,591
Purchase of Minerals in Place
Revisions of Previous Estimates 4 (8) (1) (4) (9)
Improved Recovery
Extensions and Discoveries
Production (2) (11) (7) (93) (113)
Sales of Minerals in Place
Reserves at December 31, 2016 15 368 4 3,484 3,871
Reserves at December 31, 2016 977 878 9,273 5,520 3,135 2,485 1,007 3,837 741 22,333
Developed 845 801 2,546 799 1,755 2,239 284 2,120 559 11,149
consolidated subsidiaries 845 801 2,531 799 1,651 2,239 280 338 559 9,244
equity-accounted entities 15 104 4 1,782 1,905
Undeveloped 132 77 6,727 4,721 1,380 246 723 1,717 182 11,184
consolidated subsidiaries 132 77 6,727 4,721 1,116 246 723 15 182 9,218
equity-accounted entities 264 1,702 1,966

~~(a)~~

~~Values lower than 1 BCF are not disclosed in this table.~~

~~F-151~~

~~TABLE OF CONTENTS~~

2017	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, 2016		977		878		3,738		5,520		2,767			2,485		1,003		353		741		18,462
of which: developed		845		801		1,732		799		1,651			2,239		280		338		559		9,244
undeveloped		132		77		2,006		4,721		1,116			246		723		15		182		9,218
Purchase of Minerals in Place										1											1
Revisions of Previous Estimates		315		163		66		969		134			(281)		188		(61)		6		1,499
Improved Recovery						(19)															(19)
Extensions and Discoveries				29				64		1,839							4				1,936
Production		(161)		(174)		(640)		(315)		(162)			(96)		(126)		(71)		(38)		(1,783)
Sales of Minerals in Place								(1,887)		(919)	��										(2,806)
Reserves at December 31, 2017		1,131		896		3,145		4,351		3,660			2,108		1,065		225		709		17,290
Equity-accounted entities
Reserves at December 31, 2016						15				368					4		3,484				3,871
of which: developed						15				104					4		1,782				1,905
undeveloped										264							1,702				1,966
Purchase of Minerals in Place
Revisions of Previous Estimates										13							(1,565)				(1,552)
Improved Recovery
Extensions and Discoveries
Production						(1)				(32)					(4)		(100)				(137)
Sales of Minerals in Place
Reserves at December 31, 2017						14				349							1,819				2,182
Reserves at December 31, 2017		1,131		896		3,159		4,351		4,009			2,108		1,065		2,044		709		19,472
Developed		987		771		1,247		1,421		1,776			1,878		862		1,990		519		11,451
consolidated subsidiaries		987		771		1,233		1,421		1,693			1,878		862		171		519		9,535
equity-accounted entities						14				83							1,819				1,916
Undeveloped		144		125		1,912		2,930		2,233			230		203		54		190		8,021
consolidated subsidiaries		144		125		1,912		2,930		1,967			230		203		54		190		7,755
equity-accounted entities										266											266

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-152~~F-156

TABLE OF CONTENTS

The standardized measure of discounted future net cash flows by geographical area consists of the following:

(€ million)
Italy Rest of
Europe North
Africa* *Egypt
(of which) Sub -
Saharan
Africa Kazakhstan Rest of
Asia America Australia
and
Oceania Total
December 31, 2014
Consolidated subsidiaries
Future cash inflows 24,951 29,140 96,372 �� 65,853 55,740 13,664 10,955 4,849 301,524
Future production costs (6,374) (6,856) (19,906) (18,236) (9,878) (4,158) (2,680) (1,092) (69,180)
Future development and
abandonment costs (4,698) (5,292) (9,673) (9,139) (4,576) (4,600) (1,892) (356) (40,226)
Future net inflow before income tax 13,879 16,992 66,793 38,478 41,286 4,906 6,383 3,401 192,118
Future income tax (3,583) (10,595) (35,484) (20,514) (10,400) (1,462) (2,401) (989) (85,428)
Future net cash flows 10,296 6,397 31,309 17,964 30,886 3,444 3,982 2,412 106,690
10% discount factor (4,064) (1,464) (13,905) (7,164) (19,699) (1,900) (1,353) (1,106) (50,655)
Standardized measure of discounted future net
cash flows 6,232 4,933 17,404 10,800 11,187 1,544 2,629 1,306 56,035
Equity-accounted entities
Future cash inflows 485 3,861 200 18,871 23,417
Future production costs (165) (692) (33) (5,724) (6,614)
Future development and abandonment costs (18) (104) (51) (2,032) (2,205)
Future net inflow before income tax 302 3,065 116 11,115 14,598
Future income tax (23) (426) (45) (4,608) (5,102)
Future net cash flows 279 2,639 71 6,507 9,496
10% discount factor (158) (1,442) (11) (4,327) (5,938)
Standardized measure of discounted future net
cash flows 121 1,197 60 2,180 3,558
Total consolidated subsidiaries and equity-accounted entities 6,232 4,933 17,525 11,997 11,187 1,604 4,809 1,306 59,593
December 31, 2015
Consolidated subsidiaries
Future cash inflows 16,760 18,692 58,390 44,114 34,589 13,027 8,101 3,519 197,192
Future production costs (4,995) (5,554) (13,481) (14,645) (8,846) (4,585) (3,091) (804) (56,001)
Future development and abandonment costs (4,299) (4,379) (9,457) (9,359) (4,108) (4,964) (1,644) (218) (38,428)
Future net inflow before income tax 7,466 8,759 35,452 20,110 21,635 3,478 3,366 2,497 102,763
Future income tax (1,657) (4,349) (17,195) (8,222) (4,682) (1,230) (933) (604) (38,872)
Future net cash flows 5,809 4,410 18,257 11,888 16,953 2,248 2,433 1,893 63,891
10% discount factor (2,077) (817) (7,844) (4,976) (10,561) (1,276) (970) (901) (29,422)
Standardized measure of discounted future net
cash flows 3,732 3,593 10,413 6,912 6,392 972 1,463 992 34,469
Equity-accounted entities
Future cash inflows 313 3,047 85 18,519 21,964
Future production costs (177) (1,021) (32) (5,370) (6,600)
Future development and abandonment costs (5) (95) (22) (2,118) (2,240)
Future net inflow before income tax 131 1,931 31 11,031 13,124
Future income tax (8) (251) (10) (4,088) (4,357)
Future net cash flows 123 1,680 21 6,943 8,767
10% discount factor (70) (1,016) (2) (4,358) (5,446)
Standardized measure of discounted future net
cash flows 53 664 19 2,585 3,321
Total consolidated subsidiaries and equity-accounted entities 3,732 3,593 10,466 7,576 6,392 991 4,048 992 37,790
December 31, 2016
Consolidated subsidiaries
Future cash inflows 9,627 12,898 64,371 33,524 38,271 26,903 12,263 5,789 2,815 172,937
Future production costs (4,136) (5,240) (15,408) (7,927) (13,913) (9,247) (3,498) (2,935) (658) (55,035)
Future development and abandonment costs (3,641) (3,575) (12,885) (6,981) (9,392) (3,268) (5,047) (1,313) (270) (39,391)
Future net inflow before income tax 1,850 4,083 36,078 18,616 14,966 14,388 3,718 1,541 1,887 78,511
Future income tax (237) (1,308) (15,194) (5,941) (4,525) (2,596) (953) (298) (341) (25,452)
Future net cash flows 1,613 2,775 20,884 12,675 10,441 11,792 2,765 1,243 1,546 53,059
10% discount factor (241) (365) (12,115) (8,055) (4,594) (6,536) (1,266) (501) (724) (26,342)
Standardized measure of discounted future net
cash flows 1,372 2,410 8,769 4,620 5,847 5,256 1,499 742 822 26,717
Equity-accounted entities
Future cash inflows 259 2,429 33 16,430 19,151
Future production costs (143) (974) (20) (4,614) (5,751)
Future development and abandonment costs (1) (64) (1,186) (1,251)
Future net inflow before income tax 115 1,391 13 10,630 12,149
Future income tax (21) (115) (4) (3,667) (3,807)
Future net cash flows 94 1,276 9 6,963 8,342
10% discount factor (46) (734) (4,441) (5,221)
Standardized measure of discounted future net
cash flows 48 542 9 2,522 3,121
Total consolidated subsidiaries and equity-accounted entities 1,372 2,410 8,817 4,620 6,389 5,256 1,508 3,264 822 29,838

(€ million)
December 31, 2019	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Future cash inflows		12,363		3,268		38,083		37,020		48,778		36,435		31,220		11,378		1,686		220,231
Future production costs		(5,078)		(1,175)		(6,944)		(10,934)		(15,534)		(8,239)		(8,888)		(5,060)		(293)		(62,145)
Future development and abandonment costs		(3,551)		(1,338)		(4,985)		(1,591)		(6,265)		(2,362)		(6,047)		(2,629)		(225)		(28,993)
Future net inflow before income tax		3,734		755		26,154		24,495		26,979		25,834		16,285		3,689		1,168		129,093
Future income tax		(796)		(249)		(13,632)		(7,829)		(9,926)		(5,485)		(11,379)		(1,034)		(143)		(50,473)
Future net cash flows		2,938		506		12,522		16,666		17,053		20,349		4,906		2,655		1,025		78,620
10 % discount factor		(466)		63		(5,852)		(5,822)		(6,604)		(10,832)		(1,990)		(1,187)		(443)		(33,133)
Standardized measure of discounted future net cash flows		2,472		569		6,670		10,844		10,449		9,517		2,916		1,468		582		45,487
Equity-accounted entities
Future cash inflows				25,094		380				1,787						7,730				34,991
Future production costs				(6,953)		(113)				(863)						(2,038)				(9,967)
Future development and abandonment costs				(6,519)		(23)				(59)						(145)				(6,746)
Future net inflow before income tax				11,622		244				865						5,547				18,278
Future income tax				(7,020)		(77)				(225)						(1,783)				(9,105)
Future net cash flows				4,602		167				640						3,764				9,173
10 % discount factor				(1,544)		(88)				(322)						(1,809)				(3,763)
Standardized measure of discounted future net cash flows				3,058		79				318						1,955				5,410
Total consolidated subsidiaries and equity-accounted entities		2,472		3,627		6,749		10,844		10,767		9,517		2,916		3,423		582		50,897

December 31, 2018	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Future cash inflows		18,372		4,895		43,578		39,193		53,534		40,698		33,384		14,192		2,319		250,165
Future production costs		(5,659)		(1,438)		(6,653)		(12,193)		(16,417)		(8,276)		(9,492)		(6,038)		(511)		(66,677)
Future development and abandonment costs		(4,670)		(1,350)		(4,700)		(2,769)		(6,778)		(2,640)		(5,755)		(2,467)		(291)		(31,420)
Future net inflow before income tax		8,043		2,107		32,225		24,231		30,339		29,782		18,137		5,687		1,517		152,068
Future income tax		(1,671)		(798)		(17,514)		(7,829)		(11,566)		(6,524)		(11,980)		(1,791)		(289)		(59,962)
Future net cash flows		6,372		1,309		14,711		16,402		18,773		23,258		6,157		3,896		1,228		92,106
10 % discount factor		(2,045)		(124)		(6,727)		(6,564)		(7,501)		(12,477)		(2,258)		(1,508)		(491)		(39,695)
Standardized measure of discounted future net cash flows		4,327		1,185		7,984		9,838		11,272		10,781		3,899		2,388		737		52,411
Equity-accounted entities
Future cash inflows				18,608		347				2,675						8,292				29,922
Future production costs				(4,686)		(138)				(873)						(2,192)				(7,889)
Future development and abandonment costs				(3,633)		(3)				(75)						(191)				(3,902)
Future net inflow before income tax				10,289		206				1,727						5,909				18,131
Future income tax				(6,822)		(43)				(204)						(1,839)				(8,908)
Future net cash flows				3,467		163				1,523						4,070				9,223
10 % discount factor				(1,104)		(76)				(793)						(2,009)				(3,982)
Standardized measure of discounted future net cash flows				2,363		87				730						2,061				5,241
Total consolidated subsidiaries and equity-accounted entities		4,327		3,548		8,071		9,838		12,002		10,781		3,899		4,449		737		57,652

~~F-153~~F-157

TABLE OF CONTENTS

December 31, 2017	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Future cash inflows		14,339		19,507		31,793		29,156		41,136		30,263		11,826		6,205		2,593		186,818
Future production costs		(5,091)		(5,711)		(6,677)		(6,153)		(14,790)		(6,992)		(3,653)		(2,351)		(590)		(52,008)
Future development and abandonment costs		(3,943)		(5,483)		(4,350)		(4,496)		(6,522)		(2,787)		(3,694)		(1,011)		(318)		(32,604)
Future net inflow before income tax		5,305		8,313		20,766		18,507		19,824		20,484		4,479		2,843		1,685		102,206
Future income tax		(859)		(4,490)		(10,836)		(5,709)		(6,418)		(3,970)		(757)		(699)		(303)		(34,041)
Future net cash flows		4,446		3,823		9,930		12,798		13,406		16,514		3,722		2,144		1,382		68,165
10 % discount factor		(1,633)		(1,050)		(4,566)		(6,698)		(5,430)		(9,172)		(1,239)		(777)		(607)		(31,172)
Standardized measure of discounted future net cash flows		2,813		2,773		5,364		6,100		7,976		7,342		2,483		1,367		775		36,993
Equity-accounted entities
Future cash inflows						245				2,062				11		10,797				13,115
Future production costs						(119)				(930)				(6)		(3,291)				(4,346)
Future development and abandonment costs						(1)				(66)						(535)				(602)
Future net inflow before income tax						125				1,066				5		6,971				8,167
Future income tax						(21)				(57)				(1)		(2,459)				(2,538)
Future net cash flows						104				1,009				4		4,512				5,629
10 % discount factor						(50)				(471)						(2,475)				(2,996)
Standardized measure of discounted future net cash flows						54				538				4		2,037				2,633
Total consolidated subsidiaries and equity-accounted entities		2,813		2,773		5,418		6,100		8,514		7,342		2,487		3,404		775		39,626

Changes in standardized measure of discounted future net cash flows

Changes in standardized measure of discounted future net cash flows for the years ended December 31, ~~2014, 2015~~2019, 2018 and ~~2016,~~2017, are as follows:

(€ million)
	Consolidated subsidiaries		Equity- accounted entities		Total
Standardized measure of discounted future net cash flows at December 31, 2013		56,177		2,327		58,504
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		(21,795)		(192)		(21,987)		(18,236)		(1,675)			(19,911)
- net changes in sales and transfer prices, net of production costs		(12,053)		(500)		(12,553)		(14,972)		(2,247)			(17,219)
- extensions, discoveries and improved recovery, net of future production and development costs		1,667				1,667		1,240		86			1,326
- changes in estimated future development and abandonment costs		(6,047)		223		(5,824)		(1,157)		(916)			(2,073)
- development costs incurred during the period that reduced future development costs		8,745		451		9,196		5,128		687			5,815
- revisions of quantity estimates		8,085		(325)		7,760		5,573		1,377			6,950
- accretion of discount		11,064		512		11,576		8,666		1,050			9,716
- net change in income taxes		7,049		704		7,753		6,013		(761)			5,252
- purchase of reserves in-place		67				67		260		2,579			2,839
- sale of reserves in-place		(271)				(271)
- sale of reserves in-place(a)								(429)		(88)			(517)
- changes in production rates (timing) and other		3,347		358		3,705		990		77			1,067
Net increase (decrease)		(142)		1,231		1,089		(6,924)		169	��		(6,755)
Standardized measure of discounted future net cash flows at December 31, 2014		56,035		3,558		59,593
Increase (Decrease):
- sales, net of production costs		(14,846)		(179)		(15,025)
- net changes in sales and transfer prices, net of production costs		(70,909)		(2,858)		(73,767)
- extensions, discoveries and improved recovery, net of future production and development costs		524				524
- changes in estimated future development and abandonment costs		(1,711)		(241)		(1,952)
- development costs incurred during the period that reduced future development costs		8,960		604		9,564
- revisions of quantity estimates		12,322		915		13,237
- accretion of discount		11,288		629		11,917
- net change in income taxes		29,530		530		30,060
- purchase of reserves in-place
- sale of reserves in-place		(114)				(114)
- changes in production rates (timing) and other		3,390		363		3,753
Net increase (decrease)		(21,566)		(237)		(21,803)
Standardized measure of discounted future net cash flows at December 31, 2015		34,469		3,321		37,790
Increase (Decrease):
- sales, net of production costs		(11,222)		(347)		(11,569)
- net changes in sales and transfer prices, net of production costs		(24,727)		(1,586)		(26,313)
- extensions, discoveries and improved recovery, net of future production and development costs		4,563				4,563
- changes in estimated future development and abandonment costs		(2,357)		650		(1,707)
- development costs incurred during the period that reduced future development costs		7,578		151		7,729
- revisions of quantity estimates		2,840		(131)		2,709
- accretion of discount		5,705		514		6,219
- net change in income taxes		9,200		386		9,586
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other		668		163		831
Net increase (decrease)		(7,752)		(200)		(7,952)
Standardized measure of discounted future net cash flows at December 31, 2016		26,717		3,121		29,838

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.

~~F-154~~F-158

TABLE OF CONTENTS

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

2017	Consolidated subsidiaries		Equity- accounted entities		Total
Standardized measure of discounted future net cash flows at December 31, 2016		26,717		3,121		29,838
Increase (Decrease):
- sales, net of production costs		(14,125)		(432)		(14,557)
- net changes in sales and transfer prices, net of production costs		23,940		1,482		25,422
- extensions, discoveries and improved recovery, net of future production and development costs		1,697				1,697
- changes in estimated future development and abandonment costs		(2,817)		495		(2,322)
- development costs incurred during the period that reduced future development costs		7,203		45		7,248
- revisions of quantity estimates		5,269		(2,285)		2,984
- accretion of discount		3,864		438		4,302
- net change in income taxes		(6,498)		238		(6,260)
- purchase of reserves in-place		10				10
- sale of reserves in-place		(2,995)				(2,995)
- changes in production rates (timing) and other		(5,272)		(469)		(5,741)
Net increase (decrease)		10,276		(488)		9,788
Standardized measure of discounted future net cash flows at December 31, 2017		36,993		2,633		39,626

F-159

TABLE OF CONTENTS

SIGNATURES

The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: ~~March 22, 2017~~

	~~Eni SpA~~
	~~/s/~~ ~~Andrea Simoni~~

	~~Andrea Simoni~~
	~~Title: Executive Vice President Accounting and Financial Statements Department~~

April 2, 2020

Eni SpA

~~F-155~~/s/ MASSIMO MONDAZZI

Massimo Mondazzi
Title: Chief Financial Officer

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

	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’s~~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 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 first generation feedstock (vegetable oils). Second generation 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) ~~formerly AEEG (Authority for Electricity and Gas)~~			The Italian Regulatory Authority for ~~Electricity Gas~~Energy, Networks and ~~Water~~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 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).
	Concession contracts			Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive right on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state.

	Condensates			Condensates 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.

	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 1 and Scope 2 GHG emissions of Eni’s main activities (on an operatorship basis) and produced energy, converted for homogeneity into barrels of oil equivalent.
	EPC			Engineering, Procurement and Construction.
	EPCI			Engineering, Procurement, Construction and Installation.
	Exploration			Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.
	FPSO			Floating Production Storage and Offloading System.
	FSO			Floating Storage and Offloading System.
	Greenhouse Gases (GHG)			Gases in the atmosphere, transparent to solar radiation, that trap infrared radiation emitted by the earth’s surface. The greenhouse gases relevant within Eni’s activities are carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). GHG emissions are commonly reported in CO2 equivalent (CO2eq) according to Global Warming Potential values in line with IPCC AR4, 4th Assessment Report.
	Infilling wells			Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
	LNG			Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas.
	LPG			Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
	Margin			The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
	Mineral Potential			(Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage.

	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 GHG Lifecycle Emissions			Overall Scope 1,2 and Scope 3 GHG emissions associated with Eni sold products along their value chain, net of carbon sinks;
	Net Carbon Footprint			Overall Scope 1 and Scope 2 GHG emissions associated with Eni’s operations, net of carbon sinks.
	Net-Carbon Intensity			Ratio between the net-Absolute GHG lifecycle emissions and the energy content of products sold.
	Network Code			A code containing norms and regulations for access to, management and operation of natural gas pipelines.

						Page
	Certain defined terms					ii
	Presentation of financial and other information					ii
	Statements regarding competitive position .					ii
	Glossary .					iii
	Abbreviations and conversion table					~~vii~~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					4
	~~Exchange Rates~~					53
	Risk ~~factors~~factors.					64
	Item 4. INFORMATION ON THE COMPANY					2725
	History and development of the Company					2725
	BUSINESS OVERVIEW					3233
	Exploration & Production					3233
	Gas & Power .					6258
	Refining & Marketing &and Chemicals .					6763
	Corporate and Other activities .					7570
	Research and development .					7571
	Insurance .					7774
	Environmental matters .					7874
	Regulation of Eni’s businesses					8682
	Property, plant and equipment .					9289
	Organizational structure					9289
	Item 4A. UNRESOLVED STAFF COMMENTS .					9289
	Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS					9390
	Executive summary					9390
	Critical accounting estimates					9895
	~~2014-2016~~ Group results of operations					9897
	Liquidity and capital resources					~~111~~105
	Recent developments					~~118~~109
	Management’s expectations of operations .					~~118~~110
	Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES					~~128~~119
	Directors and Senior Management .					119
	Compensation					128
	~~Compensation~~Board practices.					~~137~~
	~~Board practices~~					~~152~~128
	Employees					~~163~~140
	Share ownership					~~164~~141
	Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS					~~165~~142
	Major Shareholders					~~165~~142
	Related party transactions					~~165~~142
	Item 8. FINANCIAL INFORMATION					~~166~~143
	Consolidated Statements and other financial information .					~~166~~143
	Significant changes					~~166~~143
	Item 9. THE OFFER AND THE LISTING					~~167~~144
	Offer and listing details					~~167~~144
	Markets .					~~168~~144
	Item 10. ADDITIONAL INFORMATION					~~169~~146
	Memorandum and Articles of Association					~~169~~146
	Material contracts					~~176~~153
	Exchange controls					~~177~~153
	Taxation					~~177~~153
	Documents on display					~~182~~158
	Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .					~~182~~159
	Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES					~~185~~162
	Item 12A. Debt securities					~~185~~162
	Item 12B. Warrants and rights					~~185~~162
	Item 12C. Other ~~securities~~securities.					~~185~~162
	Item 12D. American Depositary Shares .					~~185~~162
	PART II
	Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES					~~188~~164
	Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS					~~188~~164
	Item 15. CONTROLS AND ~~PROCEDURES~~PROCEDURES.					~~188~~164
	Item 16. [RESERVED]					~~189~~165
	Item 16A. Board of Statutory Auditors financial ~~expert~~expert.					~~189~~165
	Item 16B. Code of Ethics					~~189~~165
	Item 16C. Principal accountant fees and services .					~~189~~165
	Item 16D. Exemptions from the Listing Standards for Audit Committees .					~~191~~167
	Item 16E. Purchases of equity securities by the issuer and affiliated purchasers					~~191~~167
	Item 16F. Change in Registrant’s Certifying Accountant					~~191~~167
	Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company ~~Manual~~Manual.					~~191~~168
	Item 16H. Mine safety disclosure .					~~194~~170
	PART III
	Item 17. FINANCIAL ~~STATEMENTS~~STATEMENTS.					~~195~~171
	Item 18. FINANCIAL ~~STATEMENTS~~STATEMENTS.					~~195~~171
	Item 19. EXHIBITS					~~195~~171

	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 ~~in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating~~regulates relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.

	Proved reserves			Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
	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.
	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.
	Scope 3 GHG Emissions			Indirect emissions associated with Eni products along their full value chain.
	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.
	~~Strategic Storage~~			~~According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.~~
	Take-or-pay			Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.

	Title Transfer Facility			The Title Transfer Facility, more commonly known as TTF, is a virtual trading point for natural gas in the Netherlands. TTF Price is quoted in euro per megawatt hour and, for business day, is quoted day-ahead, i.e. delivered next working day after assessment.
	UN SDGs			The Sustainable Development Goals (SDGs) are the blueprint to achieve a better and more sustainable future for all by 2030. Adopted by all United Nations Member States in 2015, they address the global challenges the world is facing, including those related to poverty, inequality, climate change, environmental degradation, peace and justice. For further detail see the website https://unsdg.un.org
	Upstream/Downstream			The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.
	Upstream GHG Emission intensity			Ratio between 100% Scope 1 GHG emissions from Upstream operated assets and 100% gross operated production (expressed in barrel of oil equivalent).

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	~~billion barrels~~= million British thermal unit
ktonnes	=	thousand tonnes

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
R&M & C	=	the Refining & Marketing and Chemicals ~~segment~~
~~E&C~~	=	~~the Engineering & Construction~~ segment

1 acre	= 0.405 hectares
1 barrel	= 42 U.S. gallons
1 BOE	= 1 barrel of crude oil	= ~~5,458~~5,408 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 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)

	Year ended December 31,
	2012		2013		2014		2015		2016
	(€ million except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA
Net sales from continuing operations		115,419		104,117		98,218		72,286		55,762
Operating profit (loss) by segment from continuing operations
Exploration & Production		19,190		15,349		10,727		(959)		2,567
Gas & Power		(3,129)		(2,923)		64		(1,258)		(391)
Refining & Marketing and Chemicals		(1,941)		(2,261)		(2,811)		(1,567)		723
Corporate and Other activities		(641)		(736)		(518)		(497)		(681)
Impact of unrealized intragroup profit elimination and other consolidation adjustments (1)		2,094		928		1,503		1,205		(61)
Operating profit (loss) from continuing operations		15,573		10,357		8,965		(3,076)		2,157
Net profit (loss) attributable to Eni from continuing operations		4,870		5,808		1,720		(7,952)		(1,051)
Net profit (loss) attributable to Eni from discontinued operations		3,520		(488)		(417)		(826)		(413)
Net profit (loss) attributable to Eni		8,390		5,320		1,303		(8,778)		(1,464)
Data per ordinary share (euro) (2)
Operating profit (loss):
– basic		4.30		2.86		2.48		(0.85)		0.60
– diluted		4.30		2.86		2.48		(0.85)		0.60
Net profit (loss) attributable to Eni basic and diluted from continuing operations		1.34		1.60		0.48		(2.21)		(0.29)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		0.97		(0.13)		(0.12)		(0.23)		(0.12)
Net profit (loss) attributable to Eni basic and diluted		2.32		1.47		0.36		(2.44)		(0.41)
Data per ADR ($) (2) (3)
Operating profit (loss):
– basic		11.05		7.59		6.59		(1.90)		1.33
– diluted		11.05		7.59		6.59		(1.90)		1.33
Net profit (loss) attributable to Eni basic and diluted from continuing operations		3.45		4.26		1.27		(4.90)		(0.65)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		2.50		(0.36)		(0.31)		(0.51)		(0.25)
Net profit (loss) attributable to Eni basic and diluted		5.95		3.90		0.96		(5.41)		(0.90)

	High		Low		Average (1)		At period end
	(U.S. dollars per €)
Year ended December 31,
2012		1.35		1.21		1.29		1.32
2013		1.38		1.28		1.33		1.38
2014		1.39		1.21		1.33		1.21
2015		1.20		1.05		1.11		1.09
2016		1.15		1.04		1.10		1.06

	High		Low		At period end
	(U.S. dollars per euro)
September 2016		1.13		1.12		1.12
October 2016		1.12		1.09		1.10
November 2016		1.11		1.06		1.06
December 2016		1.08		1.04		1.06
January 2017		1.08		1.04		1.08
February 2017		1.08		1.05		1.06